10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 _____________________________________________________________________________

FORM 10-K

 ____________________________________________________________________________

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year ended December 31, 2019

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number: 001-36542

 ______________________________________________________________

TerraForm Power, Inc.

(Exact name of registrant as specified in its charter)

 ____________________________________________________________________________

Delaware				46-4780940
(State or other jurisdiction of incorporation or organization)				(I. R. S. Employer Identification No.)
200 Liberty Street,	14th Floor	New York	New York	10281
(Address of principal executive offices)				(Zip Code)

646-992-2400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock, Class A, par value $0.01	TERP	Nasdaq Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None

___________________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.  Yes  ☒   No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  ☐  No  ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ☐    No  ☒

As of June 30, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the voting and non-voting common equity of the registrant, held by non-affiliates of the registrant (based upon the closing sale price of shares of Class A Common Stock of the registrant on the Nasdaq on such date), was approximately $1.1 billion.

As of February 28, 2020, there were 226,521,289 shares of Class A Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2020 annual meeting of stockholders (the “2020 Proxy Statement”) are incorporated by reference into Part III of this Form 10-K where indicated. The 2020 Proxy Statement will be filed with the U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.

TerraForm Power, Inc. and Subsidiaries

Table of Contents

Form 10-K

Part I. General Information
Item 1.	Business	7
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	49
Item 3.	Legal Proceedings	51
Item 4.	Mine Safety Disclosures	51
Part II. Financial Information
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	51
Item 6.	Selected Financial Data	54
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	76
Item 8.	Financial Statements and Supplementary Data	78
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	78
Item 9A.	Controls and Procedures	78
Item 9B.	Other Information	81
Part III. Executive Information
Item 10.	Directors, Executive Officers and Corporate Governance	82
Item 11.	Executive Compensation	82
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	82
Item 13.	Certain Relationships and Related Transactions, and Director Independence	82
Item 14.	Principal Accounting Fees and Services	82
Part IV. Exhibits
Item 15.	Exhibits, Financial Statement Schedules	83
Item 16.	Form 10-K Summary	83

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (the “Annual Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks, and uncertainties and typically include words or variations of words such as “expect,” “anticipate,” “believe,” “intend,” “plan,” “seek,” “estimate,” “predict,” “project,” “opportunities,” “goal,” “guidance,” “outlook,” “initiatives,” “objective,” “forecast,” “target,” “potential,” “continue,” “would,” “will,” “should,” “could,” or “may” or other comparable terms and phrases. All statements that address operating performance, events, or developments that TerraForm Power, Inc. (“TerraForm Power” and, together with its subsidiaries, the “Company”) expects or anticipates will occur in the future are forward-looking statements. They may include estimates of expected cash available for distribution, distributions growth, earnings, revenues, income, loss, capital expenditures, liquidity, capital structure, margin enhancements, cost savings, future growth, financing arrangements and other financial performance items (including future distributions per share), descriptions of management’s plans or objectives for future operations, products, or services, or descriptions of assumptions underlying any of the above. Forward-looking statements provide the Company’s current expectations or predictions of future conditions, events, or results and speak only as of the date they are made. Although the Company believes its expectations and assumptions are reasonable, it can give no assurance that these expectations and assumptions will prove to have been correct, and actual results may vary materially.

Important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are listed below and further disclosed under the section entitled Item 1A. Risk Factors:

•risks related to the proposed acquisition of all our outstanding common stock by an affiliate of Brookfield Asset Management Inc. (“Brookfield”) including whether it will be approved by shareholders and ultimately consummated;

•risks related to weather conditions at our wind and solar assets;

•the willingness and ability of counterparties to fulfill their obligations under offtake agreements;

•price fluctuations, termination provisions and buyout provisions in offtake agreements;

•our ability to enter into contracts to sell power at acceptable prices and terms, including as our offtake agreements expire;

•our ability to compete against traditional utilities and renewable energy companies;

•pending and future litigation;

•our ability to successfully close the acquisitions of, integrate or realize the anticipated benefits from the projects that we acquire from third parties, including our recently acquired portfolio of distributed generation assets;

•our ability to close, implement and realize the benefit of our cost and performance enhancement initiatives, including long-term service agreements and our ability to realize the anticipated benefits from such initiatives;

•equipment failure;

•risks related to the ability of our hedging activities to adequately manage our exposure to commodity and financial risk;

•risks related to the outbreak of COVID-19 coronavirus, including its impact on supply chains, personnel, contract counterparties and financial markets;

•risks related to our operations being located internationally, including our exposure to foreign currency exchange rate fluctuations and political and economic uncertainties;

•government regulation, including compliance with regulatory and permit requirements and changes in tax laws, market rules, rates, tariffs, environmental laws, consumer protection laws, data privacy laws and policies affecting renewable energy;

•the regulated rate of return of renewable energy facilities in our Regulated Solar and Wind segment, a reduction of which could have a material negative impact on our results of operations;

•our ability to grow and make acquisitions with cash on hand, which may be limited by our cash distribution policy;

•fraud, bribery, corruption or other illegal acts;

•health, safety, security and environmental risk;

•the condition of the debt and equity capital markets and our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness in the future;

•operating and financial restrictions placed on us and our subsidiaries related to agreements governing indebtedness;

•risks related to our relationship with Brookfield, including our ability to realize the expected benefits of sponsorship; and

•risks related to the effectiveness of our internal control over financial reporting.

We disclaim any obligation to publicly update or revise any forward-looking statement to reflect changes in underlying assumptions, factors, or expectations, new information, data, or methods, future events, or other changes, except as required by law. The foregoing list of factors that might cause results to differ materially from those contemplated in the forward-looking statements should be considered in connection with information regarding risks and uncertainties, which are described in this Annual Report, as well as additional factors we may describe from time to time in our other filings with the Securities and Exchange Commission (the “SEC”). We operate in a competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and you should understand that it is not possible to predict or identify all such factors and, consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

AC	Alternating Current
Adjusted EBITDA	Adjusted EBITDA is defined as net income (loss) plus depreciation, accretion and amortization, non-operating general and administrative costs, management fees to Brookfield, interest expense, income tax (benefit) expense, acquisition related expenses, and certain other non-cash charges, unusual or non-recurring items and other items that we believe are not representative of our core business or future operating performance.
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Cash available for distribution or CAFD	Cash available for distribution is defined as Adjusted EBITDA (i) minus management fees to Brookfield, (ii) minus cash distributions paid to non-controlling interests in our renewable energy facilities, if any, (iii) minus annualized scheduled interest and project level amortization payments in accordance with the related borrowing arrangements, (iv) minus average annual sustaining capital expenditures (based on the long-sustaining capital expenditure plans) which are recurring in nature and used to maintain the reliability and efficiency of our power generating assets over our long-term investment horizon, (v) plus or minus operating items as necessary to present the cash flows we deem representative of our core business operations.
DC	Direct Current
FASB	Financial Accounting Standards Board
GWh	Gigawatt hours
HLBV	Hypothetical Liquidation at Book Value
IDRs	Incentive Distribution Rights
ISDA	International Swaps and Derivatives Association, Inc.
ISONE	Independent System Operator of New England
ITC	Investment tax credit
kWh	Kilowatt hours
LIBOR	London Inter-bank Offered Rate
MW	Megawatt
MWh	Megawatt hours
Nameplate capacity	Nameplate capacity represents the maximum generating capacity of a facility as expressed in (1) direct current (“DC”), for all facilities within our Solar reportable segment, and (2) alternating current (“AC”) for all facilities within our Wind and Regulated Solar and Wind reportable segments
NYISO	New York System Operator
O&M	Operations and maintenance
Payout ratio	Total annual cash distributions paid to stockholders in a given year, divided by the CAFD generated by the Company during such year.
PPA	As applicable, Power Purchase Agreement, energy hedge contract and/or REC or SREC contract (as defined below)
PTC	Production tax credit
REC	Renewable energy certificate
Renewable energy facilities	Solar and wind power generation facilities
SREC	Solar renewable energy certificate
U.S. GAAP	Accounting principles generally accepted in the United States

In this Annual Report, all references to “$” are to U.S. dollars. Canadian dollars, Euros and British pounds sterling are identified as “C$”, “€”, and “£” respectively.

PART I

Item 1. Business.

Overview

TerraForm Power acquires, owns, and operates solar and wind assets in North America and Western Europe. We are the owner and operator of over 4,100 MW diversified portfolio of high-quality solar and wind assets underpinned by long-term contracts. Significant diversity across technologies and locations coupled with contracts across a large, diverse group of creditworthy counterparties significantly reduces the impact of resource variability on cash available for distribution and limits our exposure to any individual counterparty. We are sponsored by Brookfield Asset Management Inc. (“Brookfield”), a leading global alternative asset manager with over $540 billion in assets under management. Affiliates of Brookfield held approximately 62% of TerraForm Power’s Class A common stock (“Common Stock”) as of December 31, 2019.

TerraForm Power’s objective is to deliver an attractive risk-adjusted return to its stockholders. We expect to generate this total return with a regular distribution, which we intend to grow at 5 to 8% per annum, that is backed by stable cash flows.

TerraForm Power, formed in 2014, is a holding company and its primary asset is an equity interest in TerraForm Power, LLC (“Terra LLC”). TerraForm Power is the managing member of Terra LLC and operates, controls and consolidates the business affairs of Terra LLC. Unless otherwise indicated or otherwise required by the context, references to “we,” “our,” “us” or the “Company” refer to TerraForm Power and its consolidated subsidiaries.

Brookfield Renewable Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal (the “Brookfield Proposal”) from Brookfield Renewable Partners L.P. (“Brookfield Renewable”), an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board of Directors of the Company (the “Board”) consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a special committee (the “Special Committee”) of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into a definitive agreement (the “Reorganization Agreement”) for Brookfield Renewable to acquire all of the Company's outstanding shares of Common Stock, other than the 62% currently owned by Brookfield Renewable and its affiliates (the transactions contemplated by the Reorganization Agreement, the “Transactions”). Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

Our principal executive offices are located at 200 Liberty Street, 14th Floor, New York, New York 10281, and our telephone number is 646-992-2400. Our website address is www.terraformpower.com. Information contained on our website is not incorporated by reference into this Annual Report and does not constitute part of this Annual Report.

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The diagram below is a summary depiction of our organizational and capital structure as of December 31, 2019:

—————

(1)As of December 31, 2019, there were 226,500,807 shares of Common Stock outstanding. Orion US Holdings 1 L.P. (“Orion Holdings”) and BBHC Orion Holdco L.P. (“BBHC Holdings”), each controlled affiliates of Brookfield, together owned approximately 62% of our outstanding shares of Common Stock as of December 31, 2019. Brookfield Renewable, through its ownership interest in Orion Holdings and BBHC Holdings, has an approximately 30% indirect economic interest in TerraForm Power.

(2)Incentive Distribution Rights (“IDRs”) represent a variable interest in distributions by Terra LLC and therefore, cannot be expressed as a fixed percentage ownership interest in Terra LLC. BRE Delaware, Inc., an indirect, wholly-owned subsidiary of Brookfield (“Brookfield IDR Holder”), holds all of the IDRs of Terra LLC. See Incentive Distribution Rights within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the IDRs.

(3)See Liquidity and Capital Resources within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion regarding these financing arrangements.

(4)Terra LLC is a guarantor of the indebtedness of TerraForm Power Operating, LLC (“Terra Operating LLC”).

(5)Represents the borrowing capacity as of December 31, 2019. As of December 31, 2019, $115.5 million of letters of credit were outstanding under the Terra Operating LLC revolving credit facility (the “Revolver”), with availability of $484.5 million. There were no revolving loans drawn under the Revolver as of December 31, 2019.

(6)Certain project-level holding companies are guarantors of the indebtedness of Terra Operating LLC. These project-level holding companies do not have any indebtedness.

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Our Business Strategy

Our primary business strategy is to acquire, own and operate solar and wind assets in North America and Western Europe. We are the owner and operator of over 4,100 MW diversified portfolio of high-quality solar and wind assets, underpinned by long-term contracts. Significant diversity across technologies and locations coupled with contracts across a large, diverse group of creditworthy counterparties significantly reduces the impact of resource variability on cash available for distribution and limits our exposure to any individual counterparty. We are sponsored by Brookfield.

Our goal is to pay distributions to our stockholders that are sustainable on a long-term basis while retaining within our operations sufficient liquidity for recurring capital expenditures, and general corporate purposes. We expect to generate this return with a regular distribution, which we intend to grow at 5 to 8% per annum, supported by a target payout ratio of 80 to 85% of CAFD and our stable cash flows. We expect to achieve this growth and deliver returns by focusing on the following initiatives:

•Value-Oriented Acquisitions:

With the support of Brookfield, we focus on sourcing off-market transactions at more attractive valuations than auction processes. We believe that multi-faceted transactions such as take-privates and recapitalizations may enable us to acquire high quality assets at attractive relative values.

We have a right of first offer (“ROFO”) to acquire certain renewable power assets in North America and Western Europe owned by Brookfield and its affiliates. The ROFO portfolio currently stands at approximately 3,500 MW. Over time, as Brookfield entities look to sell these assets, we will have the opportunity to make offers for these assets and potentially purchase them if the proposed price (i) meets our investment objectives, and (ii) is the most favorable offered to Brookfield and the applicable Brookfield entities receive all necessary approvals from their independent directors and institutional partners. We also continue to maintain a call right over 500 MW (net) of operating wind power plants that are owned by a warehouse vehicle that was owned and arranged by our previous sponsor, SunEdison, Inc. (“SunEdison”), who sold its equity interest in this warehouse vehicle to an unaffiliated third party in 2017.

•Margin Enhancements:

We have sought to enhance our cash flow by optimizing the performance of our existing assets. As our long-term service agreements (collectively, the “LTSA”) for our North American and European wind fleets and North American solar fleet demonstrate, such agreements have the potential to lock in cost savings, provide contractual incentives for achieving our generation targets and increase revenue through deployment of technology.

•Organic Growth:

We continue to develop a robust organic growth pipeline of opportunities to invest in our existing fleet on an accretive basis as well as add-on acquisitions across our scope of operations. At any given time we seek to have a number of investment opportunities, including asset repowerings, site expansions and adding energy storage to existing sites.

We benefit from Brookfield’s deep operational expertise in owning, operating and developing renewable assets, as well as its significant deal-sourcing capabilities and access to capital. Brookfield is a leading global alternative asset manager and has a more than 100-year history of owning and operating assets with a focus on renewable power, property, infrastructure and private equity. Brookfield has over $540 billion of assets under management of which $50 billion are renewable power assets. Brookfield’s renewable power portfolio represents approximately 19,000 MW of generation capacity in 17 countries. It also employs over 2,800 individuals with extensive operating, development and power marketing capabilities and has a demonstrated ability to deploy capital in a disciplined manner.

Sponsorship Arrangements

On October 16, 2017, a wholly-owned subsidiary of Orion Holdings, an affiliate of Brookfield, merged with and into TerraForm Power (the “Merger”), with TerraForm Power continuing as the surviving corporation. In connection with the consummation of the Merger, TerraForm Power entered into the following suite of support and sponsorship arrangements (the “Sponsorship Transaction”) with Brookfield and certain of its affiliates:

•Master Services Agreement (the “Brookfield MSA”), with Brookfield, certain of Brookfield’s affiliates, Terra LLC and Terra Operating LLC, pursuant to which Brookfield and certain of its affiliates provide certain management and

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administrative services, including the provision of strategic and investment management services, to TerraForm Power and its subsidiaries.

•Relationship Agreement (the “Relationship Agreement”) with Brookfield, Terra LLC and Terra Operating LLC, which governs certain aspects of the relationship between Brookfield and TerraForm Power and its subsidiaries. Pursuant to the Relationship Agreement, TerraForm Power and its subsidiaries serve as the primary vehicle through which Brookfield and its affiliates acquire operating solar and wind assets in certain countries in North America and Western Europe, and Brookfield grants TerraForm Power a ROFO on any proposed transfer of certain existing projects and all future operating solar and wind projects located in such countries developed by persons sponsored by or under the control of Brookfield, subject to certain exceptions and consent rights set out therein. See Item 1A. Risk Factors. Risks Related to our Relationship with Brookfield.

•Governance Agreement (the “Governance Agreement”) with Orion Holdings and any controlled affiliate of Brookfield (other than TerraForm Power and its controlled affiliates) (such controlled affiliates together with Brookfield, the “Sponsor Group”) that by the terms of the Governance Agreement from time to time becomes a party thereto. The Governance Agreement establishes certain rights and obligations of TerraForm Power and members of the Sponsor Group that own voting securities of TerraForm Power relating to the governance of TerraForm Power.

Terra LLC is also party to an amended and restated limited liability company agreement with Brookfield IDR Holder, and a $500.0 million sponsor line of credit (the “Sponsor Line”) with Brookfield and one of its affiliates as discussed in Liquidity and Capital Resources within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. See also a discussion of the IDRs in Incentive Distribution Rights within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Corporate Governance and Management

We have a single class of shares outstanding worth one vote each. The size of our Board is currently set at seven members, of whom four are designated by Brookfield and three are independent. Under the terms of the Governance Agreement, Brookfield appoints our Chief Executive Officer, Chief Financial Officer and General Counsel for as long as the Brookfield MSA remains in effect. These three executive officers are not employees of TerraForm Power and their services are provided pursuant to the Brookfield MSA.

Our Board has established an Audit Committee and a Conflicts Committee, each consisting entirely of independent Directors. The Conflicts Committee considers, among other things, matters in which a conflict of interest exists between TerraForm Power and Brookfield. Our Board has also established a Nominating and Governance Committee, which consists of three Directors, one of whom is a Director designated by Brookfield and two of whom are independent Directors. Our Board also in December 2020 formed a Special Committee consisting entirely of independent Directors to, among other things, review, evaluate and consider the Brookfield Proposal.

Changes within Our Portfolio

The following table provides an overview of the changes within our portfolio from December 31, 2018 through December 31, 2019:

		Nameplate Capacity (MW)
	Facility Type		Number of Sites	Weighted Average Remaining Duration of PPA (Years)1
Description
Total Portfolio as of December 31, 2018		3,747.6	575	13
Acquisition of TEG assets	Solar	15.1	4	14
Acquisition of WGL Portfolio2	Solar	321.7	4,361	17
Acquisition of X-Elio PV assets	Solar	44.5	9	21
Divestitures of distributed generation assets	Solar	(6.4)	(8)	12
Total Portfolio as of December 31, 2019		4,122.5	4,941	13

———

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(1)Represents the weighted-average remaining term of PPAs calculated as of December 31, 2018, and December 31, 2019, as appropriate.

(2)Includes certain projects with a combined nameplate capacity of 11.6 MW for which the sellers had not yet received the required third party consents or had not completed construction as of December 31, 2019 (the “Delayed Projects”). The ownership of the Delayed Projects will be transferred to us once such third party consents have been received or construction has been completed, subject to certain terms and conditions. See Note 3. Acquisitions and Divestitures to our consolidated financial statements for additional details.

The below represents the major changes to our portfolio for the year ended December 31, 2019:

(i) TEG Acquisition

During the year ended December 31, 2019, we acquired four distributed generation facilities located in the U.S. with a combined nameplate capacity of 15.1 MW from third parties for a purchase price of $24.0 million. The facilities are contracted under long-term PPAs with municipal offtakers.

(ii) WGL Acquisition

On September 26, 2019, we completed the acquisition of an approximately 320 MW distributed generation portfolio in the United States from subsidiaries of AltaGas Ltd., a Canadian corporation (“AltaGas”), for a purchase price of $720.0 million, plus $15.1 million for working capital (the “WGL Acquisition”).

(iii) X-Elio Acquisition

On December 18, 2019, we completed the acquisition of an approximately 45 MW portfolio of utility-scale solar photovoltaic facilities in Spain from subsidiaries of X-Elio Energy, S.L., a Spanish corporation (the “X-Elio Acquisition”), for a total purchase price of €63.8 million (equivalent to $71.1 million at the date of the acquisition).

(iv) Sale of Six Distributed Generation Facilities in the United States

On December 20, 2019, we sold six distributed generation facilities in the United States, with a combined nameplate capacity of 6.0 MW, for a net consideration of $9.5 million.

See Note 3. Acquisitions and Divestitures to our consolidated financial statements for additional details.

Our Portfolio

Our current portfolio consists of renewable energy facilities located in the United States (including Puerto Rico) (the “U.S.”), Canada, Spain, Portugal, the United Kingdom (the “U.K.”), Chile and Uruguay with a combined nameplate capacity of over 4,100 MW as of December 31, 2019. These renewable energy facilities generally have long-term PPAs with creditworthy counterparties. As of December 31, 2019, on a weighted-average basis (based on MW), our PPAs had a remaining life of 13 years and counterparties to our PPAs had, on average, an investment grade credit rating.

The following table lists the renewable energy facilities that comprise our portfolio as of December 31, 2019:

Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Counterparty	Weighted Average Remaining Duration of PPA (Years)1
Distributed Generation:
United States:
Solar Distributed Generation:
Arcadia Solar3	U.S.2	172.8	201	Various	15
CD DG Portfolio	U.S.2	77.8	42	Various	14
SFGF II3	U.S.2	73.9	50	Various	19
DG 2015 Portfolio 2	U.S.2	48.1	30	Various	16
U.S. Projects 2014	U.S.2	45.4	41	Various	15
DG 2014 Portfolio 1	U.S.2	44.0	46	Various	15

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Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Counterparty	Weighted Average Remaining Duration of PPA (Years)1
TEG	U.S.2	48.9	60	Various	10
SFRC3	Minnesota	26.6	5	Various	22
Hudson Energy Solar	U.S.2	25.2	66	Various	10
MA Solar	Massachusetts	21.1	4	Various	23
Summit Solar Projects	U.S.2	19.6	50	Various	8
U.S. Projects 2009-2013	U.S.2	14.8	72	Various	17
SUNE XVIII	U.S.2	16.1	21	Various	11
SFGF3	Georgia	14.0	27	Georgia Power Company	22
California Public Institutions	California	13.5	5	The State of California	14
Enfinity	U.S.2	13.2	15	Various	12
MA Operating	Massachusetts	12.2	4	Various	14
Duke Operating	North Carolina	10.0	3	Duke Energy	11
SunE Solar Fund X	U.S.2	8.8	12	Various	11
Tinkham Hill Expansion	Massachusetts	2.5	1	Fairhaven Housing Authority	20
SFEE3	Massachusetts	3.2	1	Affordable Interior Systems, Inc.	17
Solar Residential Rooftops:
ASD Solar / SF Echo3	U.S.2	21.2	4,068	Various	14
Fuel Cells:
Arcadia Fuel Cells3	U.S.2	10.0	9	Various	16
Canada:
Summit Solar Projects	Ontario	3.8	7	Ontario Power Authority	12
Moose Power I	Ontario	4.7	13	Ontario Power Authority	14
Total Distributed Generation		751.4	4,853		15

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Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Counterparty	Weighted Average Remaining Duration of PPA (Years)1
Solar Utility:
United States:
Mount Signal I (Imperial Valley Solar I)	California	265.8	1	San Diego Gas & Electric	19
Regulus Solar	California	81.6	1	Southern California Edison	15
Blackhawk Solar Portfolio	U.S.2	72.8	10	Various	16
North Carolina Portfolio	North Carolina	26.4	4	Progress Energy Carolinas, Inc.	10
Atwell Island	California	23.5	1	Pacific Gas and Electric	18
Nellis Solar Power Plant	Nevada	14.0	1	Nellis Air Force Base	8
Alamosa	Colorado	8.2	1	Southwestern Public Service Company	8
CalRENEW-1	California	6.3	1	Pacific Gas and Electric	10
Chile:
Amanecer Solar CAP	Chile	101.6	1	Compañía Minera del Pacífico	14
Canada:
Northern Lights	Ontario	25.4	2	Ontario Power Authority	14
Marsh Hill	Ontario	18.5	1	Ontario Power Authority	15
SunE Perpetual Lindsay	Ontario	15.5	1	Ontario Power Authority	15
United Kingdom:
Norrington	U.K.	11.1	1	Statkraft AS	9
Total Solar Utility		670.7	26		16
Wind Utility:
United States:
California Ridge	Illinois	227.0	1	Tennessee Valley Authority	13
Bishop Hill	Illinois	211.4	1	Tennessee Valley Authority	13
Rattlesnake	Texas	207.2	1	Bank of America Merrill Lynch	8
Prairie Breeze I	Nebraska	200.6	1	Omaha Public Power District	19
South Plains I	Texas	200.0	1	Morgan Stanley	10
Cohocton	New York	125.0	1	Market Sales (NYISO / ISONE)	1
Stetson I & II	Maine	82.5	2	ISONE / Harvard University	5
Rollins Wind	Maine	60.0	1	Emera Maine / Central Maine Power	12
Mars Hill	Maine	42.0	1	New Brunswick Power	2
Sheffield	Vermont	40.0	1	Burlington Electric Department / Vermont Electric Coop / Washington Electric Coop	8
Steel Winds I & II	New York	35.0	2	Market Sales (NYISO / ISONE)	—
Bull Hill	Maine	34.5	1	NSTAR Electric Company	8
Kaheawa Wind Power I	Hawaii	30.0	1	Maui Electric Company	6
Kahuku	Hawaii	30.0	1	Hawaiian Electric Company	11
Kaheawa Wind Power II	Hawaii	21.0	1	Maui Electric Company	13
Portugal:

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Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Counterparty	Weighted Average Remaining Duration of PPA (Years)1
Penamacor 3B	Portugal	25.2	1	Energias de Portugal	9
Sabugal	Portugal	25.2	1	Energias de Portugal	9
Penamacor 1	Portugal	20.0	1	Energias de Portugal	9
Penamacor 2	Portugal	20.0	1	Energias de Portugal	9
Penamacor 3A	Portugal	14.7	1	Energias de Portugal	9
Penamacor 3B Ext 1	Portugal	14.7	1	Energias de Portugal	9
Sabugal Ext2	Portugal	12.0	1	Energias de Portugal	9
Penamacor 3B Ext 2	Portugal	8.0	1	Energias de Portugal	9
Sabugal Ext 1	Portugal	4.0	1	Energias de Portugal	9
Uruguay:
Carapé I	Uruguay	52.3	1	Government of Uruguay	19
Carapé II	Uruguay	43.1	1	Government of Uruguay	16
Canada:
Raleigh	Ontario	78.0	1	Ontario Power Authority	11
Total Wind Utility		1,863.4	29		10
Regulated Solar and Wind
Spain Wind:
Seron 1	Spain	50.0	1	Government of Spain / Market Sales	9
Tesosanto	Spain	50.0	1	Government of Spain / Market Sales	12
Abuela Santa Ana	Spain	49.5	1	Government of Spain / Market Sales	9
Montegordo	Spain	48.0	1	Government of Spain / Market Sales	11
Santa Catalina Cerro Negro	Spain	41.5	1	Government of Spain / Market Sales	13
Viudo I	Spain	40.0	1	Government of Spain / Market Sales	13
Sierra de las Carbas	Spain	40.0	1	Government of Spain / Market Sales	10
Tijola	Spain	36.8	1	Government of Spain / Market Sales	9
Colmenar 2	Spain	30.0	1	Government of Spain / Market Sales	8
La Noguera	Spain	29.9	1	Government of Spain / Market Sales	10
Viudo II	Spain	26.0	1	Government of Spain / Market Sales	13
Los Isletes	Spain	25.3	1	Government of Spain / Market Sales	10
Las Vegas	Spain	23.0	1	Government of Spain / Market Sales	9
La Caldera	Spain	22.5	1	Government of Spain / Market Sales	10
Valcaire	Spain	16.0	1	Government of Spain / Market Sales	13
Seron 2	Spain	10.0	1	Government of Spain / Market Sales	9
Spain Concentrated Solar Power:
Extresol 1	Spain	49.9	1	Government of Spain / Market Sales	15
Extresol 2	Spain	49.9	1	Government of Spain / Market Sales	16
Extresol 3	Spain	49.9	1	Government of Spain / Market Sales	18
Manchasol 2	Spain	49.9	1	Government of Spain / Market Sales	17
Serrezuela	Spain	49.9	1	Government of Spain / Market Sales	19

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Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Counterparty	Weighted Average Remaining Duration of PPA (Years)1
Spain Photovoltaic Solar:
Bond3	Spain	33.3	7	Government of Spain / Market Sales	21
Calasparra3	Spain	9.0	1	Government of Spain / Market Sales	19
IFM	Spain	4.4	3	Government of Spain / Market Sales	19
Alcardete3	Spain	2.3	1	Government of Spain / Market Sales	19
Total Regulated Solar and Wind		837.0	33		13
Total Renewable Energy Facilities		4,122.5	4,941		13

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(1)Calculated as of December 31, 2019.

(2)These portfolios consist of renewable energy facilities located in multiple locations within the U.S., as follows:

a.Arcadia Solar Portfolio: Arizona, California, Colorado, Connecticut, Delaware, Georgia, Hawaii, Indiana, Kentucky, Massachusetts, Maryland, Minnesota, New Jersey, New Mexico, New York, North Carolina, Rhode Island and Washington D.C.

b.CD DG Portfolio: California, Massachusetts, New Jersey, New York and Pennsylvania.

c.SFGF II: Colorado, Connecticut, Massachusetts, Maryland, Minnesota, New Jersey, North Carolina, Pennsylvania, Virginia and Washington D.C.

d.DG 2015 Portfolio 2: Arizona, California, Connecticut, Massachusetts, New Jersey, Utah and Vermont.

e.U.S. Projects 2014: Arizona, California, Connecticut, Georgia, Massachusetts, New Jersey, New York and Puerto Rico.

f.DG 2014 Portfolio 1: Arizona, California, Georgia, Hawaii, Massachusetts, Maryland, New Jersey, New York, Oregon, Texas, Vermont and Puerto Rico.

g.TEG: Arizona, California, Connecticut, Massachusetts, New Jersey and Pennsylvania.

h.Hudson Energy Solar: Massachusetts, New Jersey and Pennsylvania.

i.Summit Solar Projects (U.S.): California, Connecticut, Florida, Maryland and New Jersey.

j.U.S. Projects 2009-2013: California, Colorado, Connecticut, Massachusetts, New Jersey, Oregon and Puerto Rico.

k.SUNE XVIII: Arizona, California, Hawaii, Massachusetts, Maryland, Minnesota, New Hampshire, New York and Texas.

l.Enfinity Portfolio: Arizona, California and Ohio.

m.SunE Solar Fund X Portfolio: California, Maryland and New Mexico.

n.ASD Solar / SF Echo Portfolio: residential solar customers in California and Arizona.

o.Arcadia Fuel Cells Portfolio: California, Connecticut, Delaware and New York.

p.Blackhawk Solar Portfolio: Utah, Florida, Nevada and California.

(3)These portfolios were acquired during the year ended December 31, 2019.

Seasonality and Resource Availability

The amount of electricity produced and revenues generated by our solar generation facilities is dependent, in part, on the amount of sunlight, or irradiation, where the assets are located. As shorter daylight hours in the winter months result in less irradiation, the electricity generated by these facilities varies depending on the season. Irradiation can also be variable at a particular location from period to period due to weather or other meteorological patterns, which can affect operating results. As the majority of our solar power facilities are located in the Northern Hemisphere, we expect our solar portfolio’s power generation and revenue to be lower during the first and fourth quarters of each year.

Similarly, the electricity produced and revenues generated by our wind power plants depend heavily on wind conditions, which are variable and difficult to predict. Operating results for wind power plants vary significantly from period to period depending on the wind conditions during the periods in question. As our wind power plants are located in geographies with different weather conditions, there is some flattening of the seasonal variability associated with each individual wind power plant’s generation, and we expect that as the fleet expands the effect of such wind resource variability may be favorably impacted, although we cannot guarantee that we will purchase wind power facilities that will achieve such results in part or at all. Historically, our wind production has been greater in the first and fourth quarters which can partially offset any lower solar revenues in those quarters.

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We do not expect seasonality to have a material effect on our ability to pay a regular distribution. We intend to mitigate the effects of any seasonality that we experience by maintaining sufficient liquidity in order to, among other things, facilitate the payment of distributions to our stockholders.

Competition

Power generation is a capital-intensive business with numerous industry participants. We compete to acquire new renewable energy facilities with renewable energy developers, independent power producers, financial investors and certain utilities. We compete to supply energy to our potential customers with utilities and other distributed generation providers. We compete with renewable energy owners and developers, independent power producers, financial investors, utilities and distributed generation providers based on our cost of capital, operating expertise, pipeline, global footprint and brand reputation. To the extent we re-contract renewable energy facilities upon termination of a PPA or sell electricity into the merchant power market, we compete with traditional utilities and other independent power producers primarily based on cost of capital, asset location, the feasibility of customer sited generation, operations and management expertise, price (including predictability of price), the ability to monetize green attributes (such as RECs and tax incentives) of renewable power and the ease by which customers can switch to electricity generated by our renewable energy facilities. In our merchant power sales, we also compete with other types of generation resources, including gas and coal-fired power plants.

Environmental Matters

We are subject to environmental laws and regulations in the jurisdictions in which we own and operate renewable energy facilities. These laws and regulations generally require that governmental permits and approvals be obtained and maintained both before construction and during operation of these renewable energy facilities. We incur costs in the ordinary course of business to comply with these laws, regulations and permit requirements. We do not anticipate material capital expenditures for environmental compliance for our renewable energy facilities in the next several years. While we do not expect that the costs of compliance would generally have a material impact on our business, financial condition or results of operations, it is possible that as the size of our portfolio grows we may become subject to new or modified regulatory regimes that may impose unanticipated requirements on our business as a whole that were not anticipated with respect to any individual renewable energy facility. Additionally, environmental laws and regulations frequently change and often become more stringent, or subject to more stringent interpretation or enforcement, and therefore future changes could require us to incur materially higher costs which could have a material negative impact on our financial performance or results of operations.

Regulatory Matters

United States

All of the renewable energy facilities located in the United States that we own are qualifying small power production facilities (“QFs”) as defined under the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”) or “eligible facilities” of Exempt Wholesale Generators (“EWGs”) as defined under the Public Utility Holding Company Act of 2005, as amended (“PUHCA”). As a result, they and their upstream owners may be entitled to certain exemptions from federal and state regulation. Depending upon the power production capacity of the renewable energy facility in question, our QFs and their immediate project company owners may be entitled to various exemptions from wholesale ratemaking and certain other regulatory provisions of the Federal Power Act, as amended (“FPA”), and from state ratemaking, organizational and financial regulation of electric utilities. Our EWGs must be engaged exclusively in the business of owning and/or operating generating facilities and selling electric energy at wholesale and are subject to regulation for most purposes as “public utilities” under the FPA.

All of the renewable energy facility companies that we own outside of the United States are Foreign Utility Companies (“FUCOs”), as defined in PUHCA. They are exempt from state organizational and financial regulation of electric utilities, regulation under the FPA and from most provisions of PUHCA. The upstream owners of only QFs, EWGs, or FUCOs are exempt from the federal regulation under PUHCA.

In addition to QFs, EWGs, and FUCOs, we own certain fuel cell project companies that engage exclusively in retail energy sales. These project companies are not subject to regulation under the FPA; however, they are “electric utility companies” under PUHCA. We have obtained an exemption from federal regulation under PUHCA predicated on specific facts and representations made to FERC. In the event that we no longer qualify for such exemption, we could become subject to the federal books and access provisions of PUHCA and FERC’s record-keeping, accounting, and reporting obligations under PUHCA.

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We own a number of renewable energy facility companies in the United States that are “public utilities” subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), and that have obtained “market-based rate authorization” and associated blanket authorizations and waivers from FERC pursuant to the FPA, which allows such companies to sell electricity, capacity and ancillary services at wholesale at negotiated market based rates, instead of cost-of-service rates. These companies have been granted waivers of, and blanket authorizations under, certain FERC regulations that are commonly granted to market-based rate sellers, including blanket authorizations to issue securities and assume liabilities. FERC generally authorizes a company to charge market-based rates as long as the company can demonstrate that it does not have, or has adequately mitigated, market power and it cannot otherwise erect barriers to market entry. Currently, none of our project companies has been found by FERC to have the potential to exercise market power in any U.S. markets. In the event that FERC’s analysis of market power changes, or if certain other conditions of market-based rate authority are not met, FERC has the authority to impose mitigation measures or withhold or rescind market-based rate authority and require sales to be made based on cost-of-service rates, which could result in a reduction in rates. FERC requires market-based rate holders to submit quarterly reports of their wholesale sales and make additional compliance filings upon certain triggering events in order to maintain market-based rate authority. The failure to make timely filings can result in revocation or suspension of market-based rate authority, refunds of revenues previously collected and the imposition of civil penalties. FERC has authority to assess substantial civil penalties (i.e. up to approximately $1.3 million per day per violation) for failure to comply with the conditions of market-based rate authority as well as other requirements of the FPA and PUHCA.

Under Section 203 of the FPA (“FPA Section 203”), prior authorization by FERC is generally required for any direct or indirect change in control over, or merger or consolidation with, a “public utility,” facilities subject to FERC’s jurisdiction, or in certain circumstances an “electric utility company” or a “transmitting utility,” as such terms are used for purposes of FPA Section 203. All of our renewable energy facility companies that sell their output at wholesale in the continental U.S. (except our Wind power plants in Texas) and our subsidiary Evergreen Gen Lead, LLC (which owns electric transmission facilities) are subject to FERC’s jurisdiction under FPA Section 203. FERC generally presumes that the transfer of a 10% or greater direct or indirect voting interest in an entity results in a change in control of such entity for purposes of FPA Section 203. Transfers of interconnection and transmission facilities associated with our electric generation facilities and transfers of existing generation facilities could also trigger the need to obtain prior approval from FERC under FPA Section 203. Violation of FPA Section 203 can result in civil or criminal liability under the FPA, including civil penalties, and the possible imposition of other sanctions by FERC. Depending upon the circumstances, liability for violation of FPA Section 203 may attach to the public utility or the upstream holding companies involved in the transaction.

Certain of our renewable energy facilities are also subject to compliance with the mandatory Reliability Standards promulgated and enforced by the North American Electric Reliability Corporation (“NERC”) and approved by FERC. Violation of such Reliability Standards can result in civil penalties or other enforcement measures to ensure compliance under the FPA assessed to the owners and/or operators of such renewable energy facilities. In the United Kingdom, Canada, Chile, Uruguay, Portugal and Spain, we are also generally subject to the regulations of the relevant energy regulatory agencies applicable to all producers of electricity under the relevant feed-in tariff or other governmental incentive programs (collectively “FIT”) (including the FIT rates); however, it is generally not subject to regulation as a traditional public utility, i.e., regulation of our financial organization and rates other than FIT rates.

As the size of our portfolio grows, or as applicable rules and regulations evolve, we may become subject to new or modified regulatory regimes that may impose unanticipated requirements on the business as a whole that were not anticipated with respect to any individual renewable energy facility. For example, the NERC Reliability Standards approved by FERC impose fleetwide cyber security requirements regarding electronic and physical access to generating facilities in order to protect system reliability. Such requirements expand in scope after the point at which a common owner has more than 1,500 MW of reliability assets under its control in a single interconnection area and expand again once the owner has more than 3,000 MW under construction. Similarly, on September 19, 2019, FERC published a notice of proposed rulemaking (“NOPR”) to revise its PURPA regulations for QFs. Of relevance to our QFs, the NOPR proposes to revise (i) the obligation of interconnected utilities to purchase power from renewable QFs under 20 MW and the terms and conditions of such purchases, (ii) the process for third-party challenges to the QF status of self-certified projects, and (iii) the rules used to aggregate and treat as a single facility (for purposes of the 80 MW QF size limit and other exemption thresholds) renewable QFs that use the same fuel source, are owned or operated by the same person or its affiliates, and are located within a certain distance of each other. Such future changes in our regulatory status or the makeup of our fleet could require us to incur materially higher costs, which could have a material adverse impact on our financial performance or results of operations. Similarly, although we are not currently subject to regulation as an electric utility in the foreign markets in which we provide our renewable energy services, our regulatory position in these markets could change in the future. Any local, state, federal or international regulations could place significant restrictions on our ability to operate our business and execute our business plan by prohibiting or otherwise restricting our ability to sell electricity. If we were deemed to be subject to the same state, federal or foreign regulatory authorities as traditional utility companies, or if new regulatory bodies were established to oversee the renewable energy industry in the United States or in our foreign markets, our operating costs could materially increase, adversely affecting our results of operations.

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Spain

The principal revenues generated by our regulated wind and solar assets in Spain are received pursuant to a “regulated return” that is set by Spanish legislation. Pursuant to Royal Decree 413/2014, dated June 6, 2014 (the “Royal Decree 412/2014”), renewable electricity producers in Spain receive two principal payment streams: (i) the pool price for the power they produce; and (ii) a return on investment payment based on the standard investment cost for each type of plant (this second payment is not linked to the amount of power they produce). For certain technologies with a high operational expense (including our solar PV and CSP facilities in Spain), the return on investment is supplemented by a return on operations payment. The principle underpinning this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a “reasonable return” on investment (project investment rate of return) over a regulated standard investment cost for each type of plant defined by the government.

The regulated return rate for the first six-year regulatory period, which ended on December 31, 2019, was 7.39%. In November 2019, the Spanish government issued Royal Decree-Law 17/2019, which set the reasonable return at 7.09% for the next regulatory period (January 1, 2020 through December 31, 2025) for all assets. However, Royal Decree-Law 17/2019 contained an exception for all plants (i) that were commissioned prior to July 2013 and (ii) that did not have any pending litigation against the Kingdom of Spain regarding the prior regulatory change that took place in July 2013. For these excepted assets, Royal Decree-Law 17/2019 maintained 7.39% as the reasonable return for the next two regulatory periods (January 1, 2020 through December 31, 2031). As a result, all of our assets in Spain are entitled to the more favorable regulated rate of 7.39% through December 31, 2031, except for the approximately 45 MW of solar PV assets that we acquired in December 2019 and the approximately 100 MW of CSP assets that we acquired subsequent to year end, each of which are entitled to a reasonable return rate of 7.09% through December 31, 2025.

Government Incentives and Legislation

Each of the countries in which we operate has established various incentives and financial mechanisms to reduce the cost of renewable energy and to accelerate the adoption of solar and wind energy. These incentives include tax credits, cash grants, favorable tax treatment and depreciation, rebates, RECs or green certificates, net energy metering programs, feed-in tariffs and other incentives. These incentives help catalyze private sector investments in renewable energy and efficiency measures. Changes in the government incentives in each of these jurisdictions could have a material impact on our financial performance.

United States

Federal government support for renewable energy

The U.S. federal government provides an investment tax credit that allows a taxpayer to claim a credit of 30% of qualified expenditures for a solar generation facility. The U.S. government’s enactment of the Tax Cuts and Jobs Act (the “Tax Act”) did not make any changes to the existing laws surrounding tax credits for renewable energy. The ITC is currently scheduled to be reduced to 26% for solar generation facility construction that begins on or after January 1, 2020 and to 22% for solar generation facility construction that begins on or after January 1, 2021. A permanent 10% ITC is available for non-residential solar generation facility construction that begins on or after January 1, 2022.

Certain wind facilities are eligible for production tax credits, which are federal income tax credits based on the quantity of renewable energy produced and sold during the first ten years of production, or ITCs in lieu of PTCs. These credits are available only for wind power plants that began construction on or prior to December 31, 2020, but are reduced over time. The wind PTCs (and ITC in lieu of PTC) are 100% (of the amount otherwise available) in the case of a facility for which construction began by December 31, 2016, 80% (of the amount otherwise available) in the case of any facility for which construction began in 2017, 60% (of the amount otherwise available) in the case of a facility for which construction begins in 2018, 40% (of the amount otherwise available) in the case of a facility for which construction begins in 2019, and 60% (of the amount otherwise available) in the case of a facility for which construction begins in 2020. ITCs, PTCs and accelerated tax depreciation benefits generated by constructing and operating renewable energy facilities can be monetized by entering into tax equity financing agreements with investors that can utilize the tax benefits, which have been a key financing tool for renewable energy facilities. Based on our portfolio of assets, we will benefit from the ITC, PTC and an accelerated tax depreciation schedule, and we will rely on financing structures that monetize a substantial portion of these benefits and provide financing for our renewable energy facilities.

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U.S. state government support for renewable energy

Many states offer a personal and/or corporate investment or production tax credit for renewable energy facilities, which is in addition to the ITC or PTCs. Additionally, more than half of the states, and many local jurisdictions, have established property tax incentives for renewable energy facilities that include exemptions, exclusions, abatements and credits. Certain of our renewable energy facilities in the U.S. have been financed with a tax equity financing structure, whereby the tax equity investor is a member holding equity in the limited liability company that directly or indirectly owns the solar generation facility or wind power plant and receives the benefits of various tax credits.

Many state governments, utilities, municipal utilities and co-operative utilities offer a rebate or other cash incentive for the installation and operation of a renewable energy facility. Capital costs or “up-front” rebates provide funds based on the cost, size or expected production of a customer’s renewable energy facility. Performance-based incentives provide cash payments to a system owner based on the energy generated by their renewable energy facility during a pre-determined period, and they are paid over that time period. Some states also have established FIT programs that are a type of performance-based incentive where the system owner-producer is paid a set rate for the electricity their system generates over a set period of time.

A majority of states have a regulatory policy known as net metering. Net metering typically allows our customers to interconnect their on-site solar generation facilities to the utility grid and offset their utility electricity purchases by receiving a bill credit at the utility’s retail rate for energy generated by their solar generation facility that is exported to the grid. At the end of the billing period, the customer simply pays for the net energy used or receives a credit at the retail rate if more energy is produced than consumed. Some states require utilities to provide net metering to their customers until the total generating capacity of net metered systems exceeds a set percentage of the utilities’ aggregate customer peak demand.

Many states have also adopted procurement requirements for renewable energy production and/or a renewable portfolio standard (“RPS”) that requires regulated utilities to procure a specified percentage of total electricity delivered to customers in the state from eligible renewable energy sources, such as solar and wind power generation facilities, by a specified date. To prove compliance with such mandates, utilities must procure and retire RECs. System owners often are able to sell RECs to utilities directly or in REC markets.

U.S. Tax Reform

On December 22, 2017, the U.S. government enacted a comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act. The Tax Act made broad and complex changes to the U.S. tax code, including, but not limited to, (i) reducing the U.S. federal corporate rate from 35% to 21%; (ii) requiring companies to pay a one-time transition tax on certain unrepatriated earnings (where applicable) of foreign subsidiaries; (iii) generally eliminating the U.S. federal income tax on distributions received from foreign subsidiaries; (iv) requiring current inclusion in the U.S. federal taxable income of certain earnings of controlled foreign corporations; (v) eliminating the corporate alternative minimum tax (“AMT”) and changing how existing AMT credits may be realized; (vi) creating the base erosion anti-abuse tax, a new minimum tax; (vii) creating a new limitation on the deductible interest expense; and (viii) changing rules related to uses and limitations of net operating loss (“NOL”) carryforwards created in tax years beginning after December 31, 2017. The federal corporate tax rate reduction is expected to have a favorable impact on our business but this favorable impact is expected to be offset by a more or less equal negative impact of the interest expense deduction and loss carryforward limitations. The other measures of the Tax Act are not expected to significantly impact our current portfolio.

International

The international markets in which we operate or may operate in the future also typically have in place regimes to promote renewable energy. These mechanisms vary from country to country. Our objective is to grow our distribution through the growth of our portfolio in North America and Western Europe. In seeking to achieve this growth, we may make investments, like our investment in our European platform, that, to some extent, rely on governmental incentives in international jurisdictions.

In Spain, under Royal Decree 413/2014, renewable electricity producers receive a regulated return set by legislation consisting of two components: (i) the merchant price for the power they produce and (ii) a return on investment payment per MW of installed capacity. For solar plants, there is an additional return on operations payment per MWh produced. This program is intended to allow renewable energy producers to recover development costs and obtain a reasonable rate of return on their investment. The regulated return rate is set every six years. The first six-year regulatory period started on July 14, 2013 and ended on December 31, 2019. In November 2019, the Spanish government approved a new regulated return rate for the second regulatory period, which began on January 1, 2020 and runs through December 31, 2025. See Item 1. Business -Regulatory Matters - Spain.

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In Canada, our portfolio of operating renewable assets is located in the province of Ontario, which has historically sought to increase the contribution of renewables in the supply mix by offering long-term contracts with government-owned entities through competitive requests for proposals or feed-in tariffs. The new Ontario provincial government that took office in June 2018 has since indicated that historic levels of support for renewables will not be sustained in the near term and in December 2019 directed the Independent Electricity System Operator of Ontario to solicit feedback from generators on potential cost-lowering opportunities that would reduce electricity rates for consumers while maintaining grid reliability. See Item 1A. Risk Factors - “Laws, governmental regulations and policies supporting renewable energy, and specifically solar and wind energy (including tax incentives), could change at any time, including as a result of new political leadership, and such changes may materially adversely affect our business and our growth strategy.”

In Portugal, there are feed-in tariff contracts that fix payment terms for the duration of the contract. For contracts awarded in 2006 and 2007, the contract term is 15 years. During the European Union bailout following the financial crisis of 2008, the Portuguese government sought to raise funds to reduce its electricity tariff deficit by offering wind generators the option to extend their initial regulatory life in return for upfront payment. The extension is for an additional 7 years with a cap-and-floor price following expiry of the feed-in-tariff. Incentives are also in place for repowering existing capacity at a lower rate.

In Uruguay, we benefit from a government promoted concession agreement and a long-term PPA with UTE - Administracion Nacional de Usinas y Transmisiones Electricas, the Republic of Uruguay’s state-owned electricity company. Under this PPA, we are required to deliver power at a fixed rate for the contract period, in all cases inflation adjusted.

Business Segments

We have three reportable segments: Solar, Wind, and Regulated Solar and Wind. These segments, which represent our entire portfolio of renewable energy facilities, have been determined based on the management approach. The management approach designates the internal reporting used by management for making decisions and assessing performance as the source of the reportable segments. Our reportable segments represent an aggregation of operating segments. An operating segment is defined as a component of an enterprise that engages in business activities from which it may earn revenues and incur expenses, and that has discrete financial information that is regularly reviewed by the chief operating decision makers (“CODM”) in deciding how to allocate resources. Our Chief Executive Officer and Chief Financial Officer have been identified as the CODMs.

Our operating segments consist of: (i) Distributed Generation, North America Solar Utility and International Solar Utility, which are aggregated into the Solar reportable segment; (ii) Northeast Wind, Central Wind, Texas Wind, Hawaii Wind, Portugal Wind and Uruguay Wind operating segments, which are aggregated into the Wind reportable segment; and (iii) the Spanish Regulated Solar and Spanish Regulated Wind operating segments that are aggregated within the Regulated Solar and Wind reportable segment. Portugal Wind, Uruguay Wind, and the Spanish Regulated Solar and Wind segments were added during the second quarter of 2018 upon the acquisition of Saeta and represent its entire operations (see Note 3. Acquisitions and Divestitures to our consolidated financial statements for additional details). The operating segments have been aggregated as they have similar economic characteristics and meet the aggregation criteria. The CODMs evaluate the performance of our operating segments principally based on operating income or loss. Corporate expenses include general and administrative expenses, acquisition costs, interest expense on corporate-level indebtedness, stock-based compensation and depreciation expense. All net operating revenues for the years ended December 31, 2019, 2018 and 2017 were earned by our reportable segments from external customers in the United States (including Puerto Rico), Canada, Spain, Portugal, the United Kingdom, Uruguay and Chile.

Major Customers

For the year ended December 31, 2019, we earned an aggregate of $338.7 million from the Spanish Electricity System, including $240.7 million from the Comisión Nacional de los Mercados y la Competencia (“CNMC”) for the year ended December 31, 2019, representing 25.6% of our net consolidated operating revenues. The CNMC is the state-owned regulator of the Spanish Electricity System who collects the funds payable, mainly from the tariffs to end user customers, and is responsible for the calculation and the settlement of regulated payments. Furthermore, we earned a total of $93.9 million from the Tennessee Valley Authority (“TVA”) for the years ended December 31, 2019, representing 10% of our net consolidated operating revenues. The TVA is a corporation wholly-owned by the U.S. government that sells power mainly to wholesale customers in several states in the Southern part on the U.S. We believe that the concentration risk with the CNMC is mitigated by, among other things, the indirect support of the Spanish government for the CNMC’s obligations and for the regulated rate system more generally. Similarly, we believe that the concentration risk of the credit risk with the TVA is mitigated by, among other things, the indirect support of the U.S. government. In California, where a portion of our solar generation fleet is located,

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we generated revenues from three public utilities located in the state. These three public utilities, in aggregate, accounted for approximately 10.9% of our net consolidated operating revenues for the year ended December 31, 2019.

See Item 1A. Business - Our Portfolio for additional details on the counterparties and customers to our offtake agreements.

Employees

As of December 31, 2019, we had 174 full-time employees, 83 of which were located in the United States and 69 in Spain. The agreements entered into between the TerraForm Power and Brookfield in connection with the Merger and Sponsorship Transaction provide for Brookfield to appoint our Chief Executive Officer, Chief Financial Officer and General Counsel. These three executive officers are not employees of TerraForm Power and their services are provided pursuant to the Brookfield MSA. Subsequent to year end, as discussed in Note 26. Subsequent Events to our consolidated financial statements, on February 11, 2020, we acquired an approximately 100 MW CSP portfolio in Spain that included 64 employees also located in Spain.

Health, Safety, Security & Environment

We promote a culture of health, safety, security and environmental leadership. We strive to achieve excellence in safety performance and to be recognized as an industry leader in accident prevention. Our overall objective is to incur zero high risk safety incidents and zero lost time injuries. We have adopted a Health, Safety, Security and Environmental (“HSS&E”) policy that includes a framework for oversight, compliance, compliance audits and the sharing of best practices both within our operations and with other affiliates of Brookfield. We maintain an HSS&E Steering Committee and require all employees, contractors, agents and others involved in our operations to comply with our established HSS&E practices.

Available Information

We make available free of charge through our website (www.terraformpower.com) the reports we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. The SEC maintains an internet site containing these reports and proxy and information statements at www.sec.gov.

The following corporate governance documents are posted on our website at www.terraformpower.com:

•Audit Committee Charter;

•Conflicts Committee Charter;

•Nominating and Corporate Governance Committee Charter;

•Board of Directors Charter;

•Board Diversity Policy;

•Code of Business Conduct and Ethics;

•Cybersecurity Policy;

•Anti-Bribery and Corruption Policy;

•Environmental Policy; and

•Positive Work Environment Policy.

If you would like a printed copy of any of these corporate governance documents, please send your request by mail to 200 Liberty Street, 14th Floor, New York, New York 10281, or by email to investors@terraform.com.

The information on our website is not incorporated by reference into this Annual Report and does not constitute part of it.

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Item 1A. Risk Factors.

The following pages discuss the principal risks we face. Any of these risk factors could have a significant or material adverse effect on our businesses, results of operations, financial condition or liquidity. They could also cause significant fluctuations and volatility in the trading price of our securities. Readers should not consider any descriptions of these factors to be a complete set of all potential risks and uncertainties that could affect us. These factors should be considered carefully together with the other information contained in this Annual Report and the other reports and materials filed by us with the SEC. Furthermore, many of these risks are interrelated, and the occurrence of certain of them may in turn cause the emergence or exacerbate the effect of others. Such a combination could materially increase the severity of the impact of these risks on our businesses, results of operations, financial condition and liquidity.

Risks Related to Proposed Transactions with Brookfield Renewable

There can be no assurance that the Transactions pursuant to the Reorganization Agreement with Brookfield Renewable will be consummated, the failure of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

On January 11, 2020, the Company received an unsolicited, non-binding proposal from Brookfield Renewable, an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% already held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board consisting solely of independent Directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a Special Committee of non-executive, disinterested and independent Directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into the Reorganization Agreement for Brookfield Renewable to acquire all of the Company's outstanding shares of Common Stock, other than the 62% currently owned by Brookfield Renewable and its affiliates. Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

We cannot predict whether the Transactions would be approved by our shareholders. We also cannot assure the timing of the consummation of the Transactions. In addition, any changes in the market prices of our Common Stock, or to the publicly issued equity securities of Brookfield Renewable, could affect whether our shareholders ultimately approve the Transactions.

If the Transactions are not consummated for any reason, we may be subject to a number of known and unknown risks, including (i) the risk that the market price of our Common Stock reflects a market assumption that the Transactions will occur and that a failure to consummate the Transactions results in a decline in the market price of our Common Stock (ii) the risk that a failure to consummate the Transactions adversely impacts our relationships with employees, vendors, creditors and other business partners and results in negative publicity or a negative impression of the Company in the investment community; and (iii) the risk that we incur significant costs associated with the Transactions. If the Transactions are ultimately approved and consummated, there can be no assurances that the expected benefits of the Transactions will be realized.

Risks Related to Our Business

The production of wind energy depends heavily on suitable wind conditions, and the production of solar energy depends on irradiance. If wind or solar conditions are unfavorable or below our estimates as a result of climate change or otherwise, our electricity production, and therefore our revenue, may be substantially below our expectations.

The electricity produced and revenues generated by a wind power plant depend heavily on wind conditions, which are variable and difficult to predict. Operating results for wind power plants vary significantly from period to period, depending on the wind conditions during the periods in question. The electricity produced and the revenues generated by a solar power plant depends heavily on insolation, which is the amount of solar energy received at a site. While somewhat more predictable than wind conditions, operating results for solar power plants can also vary from period to period depending on the solar conditions during the periods in question. We base our decisions about which sites to acquire and operate in part on the findings of long-

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term wind, irradiance and other meteorological data and studies conducted in the proposed area, which, as applicable, measure the wind’s speed and prevailing direction, the amount of solar irradiance a site is expected to receive and seasonal variations. Actual conditions at these sites, however, may not conform to the measured data in these studies and may be affected by variations in weather patterns, such as the Pacific Decadal Oscillation, which has impacted our wind energy production in Hawaii, and any potential impact of climate change. If one or more of our sites were to be subject in the future to flooding, extreme weather conditions (including severe wind and droughts), fires, natural disasters, or if unexpected geological or other adverse physical conditions (including earthquakes) were to develop at any of our sites, the generation capacity of that site could be significantly reduced or even eliminated. Therefore, the electricity generated by our power plants may not meet our anticipated production levels or the rated capacity of the turbines or solar panels located there, which could adversely affect our business, financial condition and results of operations. In some quarters the wind resources at our operating wind power plants, while within the range of our long-term estimates, have varied from the averages we expected. If the wind or solar resources at a facility are below the average level we expect, our rate of return for the facility would be below our expectations and we would be adversely affected. Projections of wind resources also rely upon assumptions about turbine placement, interference between turbines, and the effects of vegetation, land use and terrain, which involve uncertainty and require us to exercise considerable judgment. Projections of solar resources depend on assumptions about weather patterns (including snow), shading, and other assumptions which involve uncertainty and also require us to exercise considerable judgment. We or our consultants may make mistakes in conducting these wind, irradiance and other meteorological studies. Any of these factors could cause our sites to have less wind or solar potential than we expected and may cause us to pay more for wind and solar power plants in connection with acquisitions than we otherwise would have paid had such mistakes not been made, which could cause the return on our investment in these wind and solar power plants to be lower than expected.

As climate change increases the frequency and severity of severe weather conditions and may have the long-term effect of changing weather patterns, the disruptions to our sites may become more frequent and severe. In addition, our customers’ energy needs generally vary with weather conditions, primarily temperature and humidity. To the extent weather conditions are affected by climate change, our customers’ energy use could increase or decrease depending on the duration and magnitude of changing weather conditions, which could adversely affect our business, results of operations and cash flows.

If our wind and solar energy assessments turn out to be wrong, our business could suffer a number of material adverse consequences, including:

•our energy production and sales may be significantly lower than we predict;

•our hedging arrangements may be ineffective or costlier;

•we may not produce sufficient energy to meet our commitments to sell electricity or RECs and, as a result, we may have to buy potentially more expensive electricity or RECs on the open market to cover our obligations or pay damages; and

•our wind and solar power plants may not generate sufficient cash flow to make payments of principal and interest as they become due on our credit facilities, notes, and certain non-recourse debt, and we may have difficulty obtaining financing for future wind or solar power plants.

Counterparties to our PPAs may not fulfill their obligations or may seek to terminate the PPA early, which could result in a material adverse impact on our business, financial condition, results of operations and cash flows.

All but a minor portion of the electricity generated by our current portfolio of renewable energy facilities is sold under long-term PPAs, including PPAs with public utilities or commercial, industrial, residential or government end-users or hedge agreements with investment banks and creditworthy counterparties. Certain of the PPAs associated with renewable energy facilities in our portfolio allow the offtake purchaser to terminate the PPA in the event certain operating thresholds or performance measures are not achieved within specified time periods or, in certain instances, by payment of an early termination fee. PPA counterparties in our distributed generation portfolio, such as retail companies and residential customers, may become bankrupt or insolvent. If a PPA was terminated or if, for any reason, any purchaser of power under these contracts is unable or unwilling to fulfill their related contractual obligations or refuses to accept delivery of power delivered thereunder (for example, due to bankruptcy or insolvency), and if we are unable to enter a new PPA on acceptable terms in a timely fashion or at all, we would be required to sell the power from the associated renewable energy facility into the wholesale power markets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, seeking to enforce the obligations of our counterparties under our PPAs could be time consuming or costly with little certainty of success.

Certain of our PPAs allow the offtake purchaser to buy out a portion of the renewable energy facility upon the occurrence of certain events, in which case we will need to find suitable replacement renewable energy facilities to invest in.

Certain of the PPAs for renewable energy facilities in our portfolio or that we may acquire in the future give the offtake purchaser the right, in certain circumstances, to purchase all or a portion of the applicable renewable energy facility

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from us. If the offtake purchaser exercises its right to purchase all or a portion of the renewable energy facility, we would need to reinvest the proceeds from the sale in one or more renewable energy facilities with similar economic attributes in order to maintain our cash available for distribution. We may be unable to locate and acquire suitable replacement renewable energy facilities in a timely fashion, which could have a material adverse effect on our results of operations and cash available for distribution.

Most of our PPAs do not include inflation-based price increases.

In general, our PPAs do not contain inflation-based price increase provisions. To the extent that the jurisdictions in which we operate experience high rates of inflation, which increases our operating costs in those countries, we may not be able to generate sufficient revenues to offset the effects of inflation, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

We may not be able to replace expiring PPAs with contracts on similar terms. If we are unable to replace an expired distributed generation PPA with an acceptable new contract, we may be required to remove the renewable energy facility from the site or, alternatively, we may sell the assets to the site host.

We may not be able to replace an expiring PPA with a contract on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. If we are unable to replace an expiring PPA with an acceptable new revenue contract, we may be required to sell the power produced by the facility at wholesale prices which may cause a significant reduction in CAFD and be exposed to market fluctuations and risks, or the affected site may temporarily or permanently cease operations. In the case of a distributed generation facility that ceases operations, the PPA terms generally require that we remove the assets, including fixing or reimbursing the site owner for any damages caused by the assets or the removal of such assets. The cost of removing a significant number of distributed generation facilities could be material. Alternatively, we may agree to sell the assets to the site owner, but the sale price may not be sufficient to replace the revenue previously generated by the solar generation facility.

A material drop in the retail price of electricity generated by traditional utilities or electricity from other sources could limit our ability to attract new customers and adversely affect our growth.

Decreases in the retail prices of electricity supplied by traditional utilities or other clean energy sources would harm our ability to offer competitive pricing and could harm our ability to sign PPAs with customers. The price of electricity from traditional utilities could decrease for a number of reasons, including:

•the construction of a significant number of new power generation plants, including nuclear, coal, natural gas or renewable energy facilities;

•the construction of additional electric transmission and distribution lines;

•a reduction in the price of natural gas, including as a result of new drilling techniques or a relaxation of associated regulatory standards;

•energy conservation technologies and sustained public initiatives to reduce electricity consumption; and

•the development of new energy technologies that provide less expensive energy.

A shift in the timing of peak rates for electricity supplied by traditional utilities to a time of day when solar energy generation is less efficient could make solar energy less competitive and reduce demand. If the retail price of energy available from traditional utilities were to decrease, we would be at a competitive disadvantage in negotiating new PPAs and therefore we might be unable to attract new customers and our growth would be limited, and the value of our renewable energy facilities may be impaired or their useful life may be shortened.

Our ability to generate revenue from certain utility-scale solar and wind power plants depends on having interconnection arrangements and services and the risk of curtailment of our renewable energy facilities may result in a reduced return on our investments and adversely impact our business, financial condition, and results of operations.

The operation of our utility scale renewable energy facilities depends on having interconnection arrangements with transmission providers and depends on a reliable electricity grid. If the interconnection or transmission agreement of a renewable energy facility we own or acquire is terminated for any reason (for example, due to the bankruptcy or insolvency of the transmission provider) we may not be able to replace it with an interconnection or transmission arrangement on terms as favorable as the existing arrangement, or at all, or we may experience significant delays or costs in securing a replacement. Moreover, if a transmission network to which one or more of our existing power plants or a power plant we acquire is connected experiences “down time,” the affected renewable energy facility may lose revenue and be exposed to non-performance penalties and claims from its customers. Curtailment as a result of transmission system down time can arise from the need to prevent damage to the transmission system and for system emergencies, force majeure, safety, reliability,

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maintenance or other operational reasons. Under our PPAs, our offtake purchasers are not generally required to compensate us for energy and ancillary services we could have delivered during these periods of curtailment had our facilities not been curtailed. Furthermore, the owners of the transmission network will not usually compensate electricity generators for lost income due to curtailment. These factors could materially affect our ability to forecast operations and negatively affect our business, results of operations, financial condition and cash flows. One of our transmission providers, a public utility company based in California, filed for federal bankruptcy protection in January 2019. While we believe the financial impact to our business will be limited, there can be no assurance of the actual impact of the bankruptcy, or any future bankruptcies of any of our transmission providers (including other public utility companies in California to which we have exposure), on our business, financial condition, results of operations or cash flows. Moreover, seeking to enforce the obligations of our counterparties under our interconnection agreements could be time consuming or costly and could involve little certainty of success.

In addition, we cannot predict whether transmission facilities will be expanded in specific markets to accommodate or increase competitive access to those markets. Expansion of the transmission system by transmission providers is costly, time consuming and complex. To the extent the transmission system is not adequate in an area, our operating facilities’ generation of electricity may be physically or economically curtailed without compensation due to transmission capacity limitations, reducing our revenues and impairing our ability to capitalize fully on a particular facility’s generating potential. Such curtailments could have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, economic congestion on the transmission grid (for instance, a positive price difference between the location where power is put on the grid by a clean power generation asset and the location where power is taken off the grid by the facility’s customer) in certain of the bulk power markets in which we operate may occur and we may be deemed responsible for those congestion costs. If we were liable for such congestion costs, our financial results could be adversely affected.

We face competition from traditional utilities and renewable energy companies.

The solar and wind energy industries, and the broader clean energy industry, are highly competitive and continually evolving, as market participants strive to distinguish themselves within their markets and compete with large incumbent utilities and new market entrants. We believe that our primary competitors are the traditional incumbent utilities that supply energy to our potential customers under highly regulated rate and tariff structures. We compete with these traditional utilities primarily based on price, predictability of price and the ease with which customers can switch to electricity generated by our renewable energy facilities. If we cannot offer compelling value to our customers based on these factors, then our business will not grow. Traditional utilities generally have substantially greater financial, technical, operational and other resources than we do, and as a result may be able to devote more resources to the research, development, promotion and sale of their products or respond more quickly to evolving industry standards and changes in market conditions than we can. Traditional utilities could also offer other value-added products or services that could help them to compete with us even if the cost of electricity they offer is higher than ours. In addition, the source of a majority of traditional utilities’ electricity is non-renewable, which may allow them to sell electricity more cheaply than electricity generated by our solar generation facilities and wind power plants. Such non-renewable generation is typically available for dispatch at any time, as it is not dependent on the availability of intermittent resources such as wind or insolation.

We also face risks that traditional utilities could change their volumetric-based (i.e., cents per kWh) rate and tariff structures to make distributed solar generation less economically attractive to their retail customers. Currently, net metering programs are utilized in the majority of states to support the growth of distributed generation facilities by requiring traditional utilities to reimburse certain of their retail customers for the excess power they generate at the level of the utilities’ retail rates rather than the rates at which those utilities buy power at wholesale. Certain states allow its traditional utilities to assess a surcharge on customers with solar generation facilities for their use of the utility’s grid, based on the size of the customer’s solar generation facility. This surcharge reduces the economic returns for the excess electricity that the solar generation facilities produce. These types of charges, which reduce or eliminate the economic benefits of net metering, if implemented across a large number of states, could significantly change the economic benefits of solar energy as perceived by traditional utilities’ retail customers.

We also face competition from other renewable energy companies who may offer different products, lower prices and other incentives, which may impact our ability to maintain our customer base. As the solar and wind industries grow and evolve, we will also face new competitors who are not currently in the market, such as an emerging storage market. Our failure to adapt to changing market conditions and to compete successfully with existing or new competitors could limit our growth and could have a material adverse effect on our business and prospects.

There are a limited number of purchasers of utility-scale quantities of electricity, which exposes us and our utility-scale facilities to additional risk.

Since the transmission and distribution of electricity is either monopolized or highly concentrated in most jurisdictions, there are a limited number of possible purchasers for utility-scale quantities of electricity in a given geographic location,

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including transmission grid operators, state and investor-owned power companies, public utility districts and cooperatives. As a result, there is a concentrated pool of potential buyers for electricity generated by our renewable energy facilities, which may restrict our ability to negotiate favorable terms under new PPAs and could impact our ability to find new customers for the electricity generated by our renewable energy facilities should this become necessary. Furthermore, if the financial condition of these utilities and/or power purchasers deteriorated or the RPS programs, climate change programs or other regulations to which they are currently subject and that compel them to source renewable energy supplies change, demand for electricity produced by our utility-scale facilities could be negatively impacted. Within this concentrated pool, for certain of our assets, we have or in the future may increase our production capacity, thereby exposing us to additional risk in the event that demand for electricity in these territories declines.

A portion of our revenues is attributable to the sale of renewable energy credits and solar renewable energy credits, which are renewable energy attributes that are created under the laws of individual states of the United States, and our failure to be able to sell such RECs or SRECs at attractive prices, or at all, could materially adversely affect our business, financial condition and results of operation.

A portion of our revenues is attributable to the sale of RECs, SRECs and other environmental attributes of our facilities. These RECs, SRECs and other environmental attributes are created under the state laws, generally in the state where the renewable energy facility is located. We sometimes seek to sell forward a portion of our RECs, SRECs or other environmental attributes under contracts having terms in excess of one year to fix the revenues from those attributes and hedge against future declines in prices of RECs, SRECs or other environmental attributes. These programs have a finite life and our revenues may decline if and when we are unable to generate a sufficient number of RECs or SRECs. If our renewable energy facilities do not generate the amount of electricity required to earn the RECs, SRECs or other environmental attributes sold under such forward contracts or if for any reason the electricity we generate does not produce RECs, SRECs or other environmental attributes for a particular state, we may be required to make up the shortfall of RECs, SRECs or other environmental attributes under such forward contracts through purchases on the open market or make payments of liquidated damages. We have from time to time provided guarantees of Terra LLC or Terra Operating LLC as credit support for these obligations. Additionally, forward contracts for REC or SREC sales often contain adequate assurances clauses that allow our counterparties to require us to provide credit support in the form of parent guarantees, letters of credit or cash collateral.

Our ability to hedge forward our anticipated volume of RECs, SRECs or other environmental attributes is limited by market conditions, leaving us exposed to the risk of falling prices for RECs, SRECs or other environmental attributes. Utilities in many states are required by law or regulation to purchase a portion of their energy from renewable energy sources. Changes in state laws or regulations relating to RECs or SRECs may adversely affect the demand for, or availability of, RECs, SRECs or other environmental attributes and the future prices for such products. This could have an adverse effect on our business, financial condition and results of operations.

We are involved in costly and time-consuming litigation and other disputes, which require significant attention from our management, involve exposure to legal liability and may result in significant damage awards.

As more fully described in Note 20. Commitments and Contingencies to our consolidated financial statements, included in this Annual Report, we have been subject to claims arising out of our acquisition activities with respect to certain payments in connection with the acquisition of First Wind Holdings, LLC by SunEdison. D.E. Shaw Composite Holdings, L.L.C. and Madison Dearborn Capital Partners IV, L.P., as the representatives of the sellers (the “First Wind Sellers”) pursuant to the Purchase and Sale Agreement, dated as of November 17, 2014 (the “FW Purchase Agreement”) between, among others, SunEdison, the Company and Terra LLC and the First Wind Sellers have alleged a breach of contract with respect to the FW Purchase Agreement and that Terra LLC and SunEdison became jointly obligated to make $231.0 million in earn-out payments in respect of certain development assets SunEdison acquired from the First Wind Sellers under the FW Purchase Agreement, when those payments were purportedly accelerated by SunEdison’s bankruptcy and by the resignations of two SunEdison employees. The First Wind Sellers have also alleged that the Company, as guarantor of certain Terra LLC obligations under the FW Purchase Agreement, is liable for this sum. In addition, the plaintiffs have claimed legal costs and expenses and, under the applicable New York law, their claim accrues interest at a non-compounding rate of 9% per annum. We believe the allegations for both of these matters are without merit and will contest the claim and allegations vigorously. However, we cannot predict with certainty the ultimate resolution of any proceedings brought in connection with these claims.

We also have been and continue to be involved in legal proceedings, administrative proceedings, claims and other litigation that arise in the ordinary course of business, including proceedings related to the operation of our renewable energy facilities. For example, individuals or groups have in the past and may in the future challenge the issuance of a permit for a renewable energy facility or may make claims related to alleged impacts of the operation of our renewable energy facilities on adjacent properties. We are currently and/or may in the future be subject to claims, lawsuits or arbitration proceedings related to matters in tort or under contracts, employment matters, securities class action lawsuits, stockholder derivative actions, breaches of fiduciary duty, conflicts of interest, tax authority examinations or other lawsuits, regulatory actions or government inquiries

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and investigations. In addition, we are currently and/or may in the future be named as defendants in other lawsuits and regulatory actions or investigations relating to our business, some of which may claim significant damages.

In the past, companies that have experienced volatility in the market price of their stock or have had delayed SEC filings have been subject to securities class action litigation. We have been the target of such securities litigation in the past and we may become the target of additional securities litigation in the future. As more fully described in Note 20. Commitments and Contingencies to our consolidated financial statements, included in this Annual Report, the Company, Brookfield and members of our Board of Directors have been subject to shareholder claims, including the derivative and class action lawsuit filed by lead plaintiff Martin Rosson in September 2019, in connection with our funding of our acquisition of Saeta, alleging that the defendants breached their fiduciary duties to shareholders. Securities class action lawsuits and derivative lawsuits are also often brought against companies that have entered into merger agreements in an effort to enjoin the merger or seek monetary relief from the counterparties. It is possible that the Brookfield Renewable Merger would attract these types of lawsuits. Even if such lawsuits are without merit, defending against any such claims can result in substantial costs and divert management time and resources. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Brookfield Renewable Merger, then that injunction may delay or prevent the Brookfield Renewable Merger from being completed, or from being completed within the expected timeframe, which may adversely affect the Company’s business, financial position and results of operation. We cannot predict whether such lawsuits would actually arise or the occurrence, outcome or impact of any such lawsuits nor can we predict the amount of time and expense that would be required to resolve any such litigation.

Due to the inherent uncertainties of litigation and regulatory proceedings, we cannot accurately predict the ultimate outcome of any such proceedings. Unfavorable outcomes or developments relating to these proceedings, or new proceedings involving similar allegations or otherwise, such as monetary damages or equitable remedies or potential negative publicity associated with such legal actions, could have a material adverse impact on our business and financial position, results of operations or cash flows or limit our ability to engage in certain of our business activities. Settlement of claims could adversely affect our financial condition, results of operations and cash flows. In addition, regardless of the outcome of any litigation or regulatory proceedings, such proceedings are often expensive, lengthy and disruptive to normal business operations and require significant attention from our management, and may at times divert management’s attention from other business concerns.

We may not be able to successfully integrate the operations, technologies and personnel of the projects we acquire from third parties, including the distributed generation portfolio that we acquired from subsidiaries of AltaGas, which could result in a material adverse impact on our business.

We believe the acquisition of projects from third parties, including the approximately 320 MW portfolio of distributed generation facilities in the United States from subsidiaries of AltaGas, will be accretive to cash available for distribution to our stockholders on a per share basis. However, to realize the anticipated benefits of these acquisitions, the acquired projects must be successfully combined with our existing business. We may fail to realize the anticipated benefits of the acquisition and any other third party acquisitions as a result of our inability to successfully integrate the assets and, if applicable, operations, technologies and personnel of the acquired business with and into our existing business for a variety of reasons, including the following:

•failure to successfully manage relationships with existing contract counterparties;

•failure to quickly and effectively leverage the increased scale of the combined company;

•the loss of key employees; and

•potential difficulties integrating and harmonizing financial reporting systems and establishing appropriate accounting controls, reporting procedures and regulatory compliance procedures.

We may not realize the expected benefits of our LTSAs with General Electric, SMA and other O&M providers and we may be subject to risk associated with having a concentrated pool of O&M providers.

In August 2018, we executed an 11-year framework agreement with an affiliate of General Electric to provide us with long-term service agreements (“LTSAs”) for turbine operations and maintenance as well as other balance of plant services for our 1.6 GW North American wind fleet. In November 2019, we executed a 10-year framework agreement with SMA Solar Technology that, among other things, provides for the roll out, subject to receipt of third-party consents, of project level LTSAs for solar operations and maintenance services, as well as other balance of plant services across our North American solar fleet (excluding the DG Portfolio). During 2019, we also executed new LTSAs with the original equipment manufacturers for turbine operations and maintenance services for our European wind fleet.

These LTSAs are expected to improve performance of the wind and solar assets that they cover, and in certain circumstances, realize cost savings. However, we may not be able to fully realize these anticipated benefits or at all. For example, we may not achieve increased production from our wind and solar fleet or realize any of the expected cost savings. While we have put in place LTSAs on all but one of our North American wind projects, there can be no assurances that we will

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receive the necessary consents required to put the LTSA in place at the final wind project. Similarly, while we are able to implement the LTSAs with SMA at the majority of our North American solar projects without needing third party consents, there can be no assurance that will be able to procure the necessary consents needed for the remainder of the projects. Furthermore, as a result of the LTSA with GE and SMA, we have concentrated the sourcing of our North American wind and solar O&M services in two service providers. If either GE or SMA become insolvent, or otherwise are unable or unwilling to perform their obligations under the applicable LTSAs or framework agreements, it may be difficult to quickly identify alternative service providers on favorable terms, which may result in a material adverse effect on our business, financial condition and results of operations. In addition, we may disagree with our service providers on the scope or nature of their obligations in the applicable LTSAs, framework agreements and other agreements, including the calculation of liquidated damages under the LTSAs, and because of this concentration risk, any such disagreement could lead to delays in performance, costly arbitration or litigation, or other adverse developments, any of which could result in a material adverse effect on our business, financial condition and results of operations.

In addition, during 2019, as a result of our acquisition of the WGL Portfolio, we acquired a portfolio of fuel cells which are reliant on proprietary technology and intellectual property of a third party who also serves as the O&M provider for the portfolio. If this third party becomes insolvent or otherwise is unable or unwilling to perform its contractual obligations to us, we may not be able to adequately operate and maintain our fuel cell portfolio, which may have an adverse effect on us.

Maintenance, expansion and refurbishment of renewable energy facilities involve significant risks that could result in unplanned power outages or reduced output or cause significant injury or property damage.

Our facilities may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, such as the failure of a single faulty blade which caused the collapse of a tower at our Raleigh wind facility in 2018, other single blade failures at our Bishop Hill, Cal Ridge and Cohocton wind facilities during 2019 and 2020, or other failures associated with breakdowns and forced outages generally, and any decreased operational or management performance, could reduce our facilities’ generating capacity below expected levels, reducing our revenues and jeopardizing our ability to pay distributions to holders of our Common Stock at forecasted levels or at all. Incomplete performance by us or third parties under O&M agreements, including subcontractors, may increase the risks of operational or mechanical failure of our facilities which could cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment and suspension of operations, which could expose us to significant liability. Degradation of the performance of our renewable energy facilities provided for in the related PPAs may also reduce our revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability.

We may also choose to refurbish or upgrade our facilities based on our assessment that such activity will provide adequate financial returns and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future power prices. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Moreover, spare parts for wind turbines and solar facilities and key pieces of equipment may be hard to acquire or unavailable to us. Sources of some significant spare parts and other equipment are located outside of North America and the other jurisdictions in which we operate. Suppliers of some spare parts have filed, or will in the future file for, bankruptcy protection, potentially reducing the availability of parts that we require to operate certain of our power generation facilities. Suppliers may be reliant on global supply chains, including supply chains that extend to areas that are subject to economic disruptions, as is the case currently where supply chains have been disrupted by the outbreak of the COVID-19 coronavirus, which began in December 2019. Other suppliers may for other reasons cease to manufacture parts that we require to operate certain of our power generation facilities. If we were to experience a shortage of or inability to acquire critical spare parts we could incur significant delays in returning facilities to full operation, which could negatively impact the financial condition of our business, results of operations and cash flows.

Renewable energy facilities depend on a limited number of suppliers of solar panels, inverters, module turbines, towers and other system components and turbines and other equipment associated with wind and solar power plants. Any shortage, delay or component price change from these suppliers could result in construction or installation delays, which could affect the number of renewable energy facilities we are able to acquire in the future.

There have been periods of industry-wide shortage of key components, including solar panels and wind turbines, in times of rapid industry growth. The manufacturing infrastructure for some of these components has a long lead time, requires significant capital investment and relies on the continued availability of key commodity materials, potentially resulting in an inability to meet demand for these components. A shortage of key commodity materials could also lead to a reduction in the number of renewable energy facilities that we may have the opportunity to acquire in the future, or delay or increase the costs of acquisitions.

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In addition, potential acquisition of solar projects could be more challenging as a result of increases in the cost of solar panels or tariffs on imported solar panels imposed by the U.S. government. The U.S. government has imposed tariffs on imported solar cells and modules manufactured in China. If project developers purchase solar panels containing cells manufactured in China, our purchase price for renewable energy facilities may reflect the tariff penalties mentioned above. While solar panels containing solar cells manufactured outside of China are not subject to these tariffs, the prices of these solar panels are, and may continue to be, more expensive than panels produced using Chinese solar cells, before giving effect to the tariff penalties.

The declining cost of solar panels and the raw materials necessary to manufacture them has been a key driver in the pricing of solar energy systems and customer adoption of this form of renewable energy. With the stabilization or increase of solar panel and raw materials prices, our growth could slow. Although we do not purchase solar panels directly, higher cost solar panels could make future purchases of solar assets more difficult.

The repowering of existing wind and solar generation projects in our portfolio is subject to construction risks, tax risk, and risks associated with the arrangements we enter into with local stakeholders and joint venture partners.

We may from time to time seek to replace all or part of an existing wind or solar project with new more efficient equipment in order to improve performance, lower costs, decrease operational risk and extend the useful life of such a project. This process is referred to as a repowering. Repowerings could include replacing existing wind turbines, solar panels, inverters or other components with new equipment. Our ability to repower a project is dependent on, among other things, our ability to procure equipment and parts, including parts that are subject to safe harbors for federal tax credits and other incentives, and to complete all necessary construction contemplated for a particular repowering on time and on budget. The repowering of an existing generating facility may be subject to environmental, engineering, tax and construction risks that could result in cost overruns, delays and reduced performance, or in a planned repowering not happening at all. A number of factors that could cause such delays, cost over runs or reduced performance or cancellation of a planned repowering include, but are not limited to, changes in local laws or difficulties in obtaining permits, rights of way or approvals, changing engineering and design requirements, construction costs exceeding estimates for various reasons, including inaccurate engineering and planning, failures to properly estimate the cost of raw materials, components, equipment, labor or the inability to timely obtain them, unanticipated problems with project start-up, the performance of contractors, the insolvency of the head contractor or of a major equipment supplier (including panel, inverter and wind turbine supplier), a major subcontractor and/or a key equipment supplier, labor disruptions, inclement weather, defects in design, engineering or construction (including, without limitation, latent defects that do not materialize during an applicable warranty or limitation period), the occurrence of force majeure events and any unanticipated project modifications. The repowering of certain projects in the United States may also depend on the availability of equipment that is subject to safe harbors for federal tax credits and the availability of construction financing, tax equity and other forms of financing in capital markets.

A delay in the projected completion of a repowering can result in a material increase in total construction costs through higher capitalized interest charges, additional labor and other expenses, a loss of production tax credits in the United States and a resultant delay in the re-commencement of cash flow. In addition, such unexpected issues may result in increased debt service costs, operations and maintenance expenses and damage payments for late delivery or the failure to meet agreed upon generation levels. This may result in an inability to meet the higher interest and principal repayments arising from any additional debt required.

In some circumstances, we may be required to notify, consult, or obtain the consent of certain stakeholders, including landowners and municipalities, regarding a repowering transaction. Certain of these communities and partners may have or may develop interests or objectives which are different from or even in conflict with our objectives. Any such differences could have a negative impact on the success of any contemplated repowering.

We may incur unexpected expenses if the suppliers of components of our renewable energy facilities default in their warranty obligations.

The solar panels, inverters, modules and other system components utilized in our solar generation facilities are generally covered by manufacturers’ warranties, which typically range from 5 to 20 years. When purchasing wind turbines, the purchaser will enter into warranty agreements with the manufacturer which typically expire within two to five years after the turbine delivery date. In the event any such components fail to operate as required, we may be able to make a claim against the applicable warranty to cover all or a portion of the expense associated with the faulty component. However, these suppliers could cease operations and no longer honor the warranties, which would leave us to cover the expense associated with the faulty component. Our business, financial condition, results of operations and cash flows could be adversely affected if we cannot make claims under warranties covering our renewable energy facilities.

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Concentrated solar power facilities use technology that differs from traditional solar photovoltaic technology and is subject to known and unknown risks.

Our concentrated solar power (“CSP”) facilities located in Spain consist primarily of parabolic troughs that concentrate reflected light onto receiver tubes. The receiver tubes are filled with a working fluid which is heated by the concentrated sunlight and then used to heat water for a standard steam power generation system. This technology differs from that used in more common solar photovoltaic (“PV”) facilities and concentrated solar technology is much less widely used worldwide and is subject to known and unknown risks that differ from those associated with solar PV facilities. For example, the temperatures used in concentrated solar facilities can be extremely high. Fires or leaks of heated working fluid at any of our facilities could result in a loss of generating capacity and could require us to expend significant amounts of capital and other resources. Such failures could result in personal injury or loss of life, severe damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment and suspension of operations, which could expose us to significant liability. Repairing any such failure could require us to expend significant amounts of capital and other resources.

As a result of our recent acquisition of certain solar rooftop residential assets, we are subject to financing and consumer protection laws and regulations.

We recently acquired over 4,000 solar rooftop residential assets in California and Arizona. As a result of this acquisition and any future acquisitions of residential solar assets, we have become subject to certain consumer protection laws that may not be applicable to our commercial and power plant businesses, such as privacy and data security, federal truth-in-lending, consumer leasing, and equal credit opportunity laws and regulations, as well as state and local finance laws and regulations. Claims arising out of actual or alleged violations of law may be asserted against us by individuals or governmental entities and may expose us to significant damages or other penalties, including fines that could be material to our business.

Operation of renewable energy facilities involves significant risks and hazards that could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may not have adequate insurance to cover these risks and hazards.

The ongoing operation of our facilities involves risks that include the breakdown or failure of equipment, such as the failure of a single faulty blade which caused the collapse of a tower at our Raleigh wind facility in 2018, other single blade failures at our Bishop Hill, Cal Ridge and Cohocton wind facilities during 2019 and 2020, or processes or performance below expected levels of output or efficiency due to wear and tear, latent defect, design error or operator error or force majeure events, among other things. Unplanned outages of generating units, including extensions of scheduled outages, occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of generating and selling less power or require us to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations.

Our inability to efficiently operate our renewable energy facilities, manage capital expenditures and costs and generate earnings and cash flow from our assets could have a material adverse effect on our business, financial condition, results of operations and cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels (in some cases backed by liquidated damages from the contractor), the proceeds of such insurance, warranties or performance guarantees may not cover our lost revenues, increased expenses or payments should we experience equipment breakdown or non-performance by contractors or vendors.

Power generation involves hazardous activities, including delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, structural collapse and machinery failure are inherent risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate but we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Furthermore, our insurance coverage is subject to deductibles, caps, exclusions and other limitations. A loss for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations or cash flows. Furthermore, due to rising insurance costs and changes in the insurance markets, we cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Our hedging activities may not adequately manage our exposure to commodity and financial risk, which could result in significant losses or require us to use cash collateral to meet margin requirements, each of which could have a material adverse effect on our business, financial condition, results of operations and liquidity, and impair our ability to execute favorable financial hedges in the future.

Certain of our wind power plants are party to financial swaps or other similarly structured hedging arrangements (“swaps”). We may also acquire additional assets with similar hedging arrangements in the future. Under the terms of the existing swaps, certain wind power plants receive payments for specified quantities of electricity based on a fixed-price and are obligated to deliver (if physically settled) or pay (if financially settled) the counterparty the market price for the same quantities of electricity. These swaps cover quantities of electricity that we estimated are highly likely to be produced. As a result, gains or losses under the swaps are designed to be offset by decreases or increases in a facility’s revenues from spot sales of electricity in liquid markets. However, the actual amount of electricity a facility generates from operations may be materially different from our estimates for a variety of reasons, including variable wind conditions and wind turbine availability. If a wind power plant does not generate the volume of electricity required by the associated contract, we could incur significant losses if electricity prices in the market rise substantially above the fixed-price provided for in the swap arrangement. This risk is particularly acute in the ERCOT market during summer months due to low reserve margins and the attendant risk of scarcity pricing. If a wind power plant generates more electricity than is contracted in the swap arrangement, the excess production will not be hedged and the related revenues will be exposed to market price fluctuations.

Moreover, in some power markets, at times we have experienced negative power prices with respect to merchant energy sales. In these situations, we must pay grid operators to take our power. Because our tax investors receive production tax credits from the production of energy from our wind plants, it may be economical for the plant to continue to produce power at negative prices, which results in the applicable facility paying for the power it produces. In addition, certain swap arrangements are settled with reference to energy prices (or locational marginal prices) at a certain hub or node on the transmission system in the relevant energy market. At the same time, revenues generated by physical sales of energy from the applicable facility may be determined by the energy price (or locational marginal price) at a different node on the transmission system. This is an industry practice used to address the lack of liquidity at individual facility locations. There is a risk, however, that prices at these two nodes differ materially, and as a result of this so called “basis risk,” we may be required to settle our swaps at prices that are higher than the prices at which we are able to sell physical power from the applicable facility, thus reducing the economic effectiveness of the swap hedges. Basis risk is particularly acute in the Texas Panhandle, where we own one wind power plant with over 200 MW of nameplate capacity, due to transmission constraints caused by line outages and high wind penetration.

We are exposed to foreign currency exchange risks because certain of our renewable energy facilities are located outside of the United States.

We generate a substantial portion of our revenues and incur a substantial portion of our expenses in currencies other than U.S. dollars. The portion of our revenues generated in currencies other than U.S. dollars may increase in the future if we continue to acquire additional assets outside of the United States. Changes in economic or political conditions in any of the countries in which we operate now or in the future could result in exchange rate movement, expropriation, new currency or exchange controls or other restrictions being imposed on our operations. As our financial results are reported in U.S. dollars, if we generate revenue or earnings in other currencies, the translation of those results into U.S. dollars can result in a significant increase or decrease in the amount of those revenues or earnings. To the extent that we are unable to match revenues received in foreign currencies with costs paid in the same currency, exchange rate fluctuations in any such currency could have a negative impact on our profitability. Our debt service requirements are primarily in U.S. dollars even though a percentage of our cash flow is generated in other foreign currencies and therefore significant changes in the value of such foreign currencies relative to the U.S. dollar could have a material negative impact on our financial condition and our ability to meet interest and principal payments on debts denominated in U.S. dollars. In addition to currency translation risks, we incur currency transaction risks whenever we or one of our facilities enter into a purchase or sales transaction using a currency other than the local currency of the transacting entity.

Given the volatility of exchange rates, there can be no assurance that we will be able to effectively manage our currency transaction and/or translation risks. It is possible that volatility in currency exchange rates will have a material adverse effect on our financial condition or results of operations. We expect to experience economic losses and gains and negative and positive impacts on earnings as a result of foreign currency exchange rate fluctuations, particularly as a result of changes in the value of the Euro.

Additionally, although a portion of our revenues and expenses are denominated in foreign currency, any distributions we pay will be denominated in U.S. dollars. The amount of U.S. dollar denominated distributions paid to our holders of our Common Stock will therefore be exposed to a certain level of currency exchange rate risk. Although we have entered into certain hedging arrangements to help mitigate some of this exchange rate risk, these arrangements may not be sufficient to

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eliminate the risk. Changes in the foreign exchange rates could have a material negative impact on our results of operations and may adversely affect the amount of cash distributions paid by us to holders of our Common Stock.

Political instability, changes in government policy, or unfamiliar cultural factors could adversely impact the value of our investments.

We are subject to geopolitical uncertainties in all jurisdictions in which we operate. We make investments in businesses that are based outside of the United States, and we may pursue investments in unfamiliar markets, which may expose us to additional risks not typically associated with investing in the United States. We may not properly adjust to the local culture and business practices in such markets, and there is the prospect that we may hire personnel or partner with local persons who might not comply with our culture and ethical business practices; either scenario could result in the failure of our initiatives in new markets and lead to financial losses. There are risks of political instability in several of the jurisdictions in which we conduct business, including, for example, social and political unrest (e.g., recent social unrest in Chile), tariffs, income inequality, refugee migration, terrorism, the potential break-up of political-economic unions (or the departure of a union member, e.g., Brexit) and political corruption. The materialization of one or more of these risks in markets where we own and operate assets could create economic uncertainty that causes disruptions to our businesses, including affecting the business of and/or our relationships with our customers, contractors and suppliers which could in turn negatively affect our financial performance. For example, although the long-term impact on economic conditions is uncertain, Brexit may have an adverse effect on the rate of economic growth in the U.K. and continental Europe.

Our business is subject to substantial governmental regulation and may be adversely affected by changes in laws or regulations, as well as liability under, or any future inability to comply with, existing or future regulations or other legal requirements.

Our business is subject to extensive federal, state and local laws in the U.S. and regulations in the foreign countries in which we operate. Compliance with the requirements under these various regulatory regimes may cause us to incur significant costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility or, the imposition of liens, fines and/or civil or criminal liability.

With the exception of certain of our utility scale plants, our renewable energy facilities located in the United States in our portfolio are QFs as defined under PURPA. Depending upon the power production capacity of the facility in question, our QFs and their immediate project company owners may be entitled to various exemptions from wholesale ratemaking and certain other regulatory provisions of the FPA, from the federal and state books and records access provisions of PUHCA and FERC’s record-keeping, accounting, and reporting obligations under PUHCA, and from state ratemaking, organizational and financial regulation of electric utilities.

On September 19, 2019, FERC published a NOPR to revise its PURPA regulations. Of relevance to our QFs, the NOPR proposes to revise (i) the obligation of interconnected utilities to purchase power from renewable QFs under 20 MW and the terms and conditions of such purchases, (ii) the process for third-party challenges to the QF status of self-certified projects, and (iii) the rules used to aggregate and treat as a single facility (for purposes of the 80 MW QF size limit and other exemption thresholds) renewable QFs that use the same fuel source, are owned or operated by the same person or its affiliates, and are located within a certain distance of each other. The public comment period on the NOPR closed on December 3, 2019.

The immediate owners of certain of our utility scale plants are EWGs, as defined under PUHCA, which allows their upstream owners to qualify for an exemption from the federal books and access provisions of PUHCA and FERC’s record-keeping, accounting, and reporting obligations under PUHCA. Certain of the EWGs also own QFs. EWGs are often subject to regulation for most purposes as “public utilities” under the FPA, including regulation of their wholesale rates and their issuances of securities and assumption of liabilities. Each of our EWGs (except Evergreen Gen Lead, LLC) has obtained “market based rate authorization” and associated blanket authorizations and waivers from FERC under the FPA, which allows it to sell electricity, capacity and ancillary services at wholesale at negotiated, market based rates, instead of cost-of-service rates, as well as waivers of, and blanket authorizations under, certain FERC regulations that are commonly granted to market based rate sellers, including blanket authorizations to issue securities and assume liabilities. FERC typically grants an entity the authority to charge market-based rates as long as the entity can demonstrate that it does not have, or has adequately mitigated, market power and it cannot otherwise erect barriers to market entry. Currently, none of our project companies or their affiliates has been found by FERC to have the potential to exercise market power in any U.S. markets. In the event that FERC’s analysis of market power changes or if certain other conditions of market-based rate authority are not met, FERC has the authority to impose mitigation measures or withhold or rescind market-based rate authority and require sales to be made based on cost-of-service rates, which could result in a reduction in rates.

In addition to QFs and EWGs, we own certain fuel cell projects in a number of U.S. states that engage exclusively in retail energy sales. These projects are not subject to regulation under the FPA; however, they are “electric utility companies”

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under PUHCA. We have obtained an exemption from federal regulation under PUHCA predicated on specific facts and representations made to FERC. In the event that we no longer qualify for such exemption, we could become subject to the federal books and access provisions of PUHCA and FERC’s record-keeping, accounting, and reporting obligations under PUHCA.

The failure of our QFs to maintain QF status may result in their owners becoming subject to significant additional regulatory requirements. In addition, the failure of the EWGs or our QFs to comply with applicable regulatory requirements may result in the imposition of civil penalties or other sanctions. FERC has the authority to assess substantial civil penalties (i.e. up to approximately $1.3 million USD per day per violation) for failure to comply with the conditions of market-based rate authority and the requirements of the FPA and PUHCA.

In particular, any person or entity that engages in FERC-jurisdictional transactions (e.g., wholesale power sales), including our EWGs and any project companies that own or operate our QFs, are subject to certain market behavior and anti-manipulation rules as established and enforced by FERC, and if they are determined to have violated those rules, will be subject to potential disgorgement of profits associated with the violation, penalties, and suspension or revocation of their market-based rate authority. If such entities were to lose their market-based rate authority, they would be required to obtain FERC’s acceptance of a cost-of-service rate schedule for wholesale sales of electric energy, capacity and ancillary services and could become subject to significant accounting, record-keeping, and reporting requirements that are imposed on FERC regulated public utilities with cost-based rate schedules.

Substantially all of our assets are also subject to the rules and regulations applicable to power generators generally, in particular the NERC Reliability Standards or similar standards in jurisdictions in which we operate. If we fail to comply with these mandatory Reliability Standards, we could be subject to sanctions, including substantial monetary penalties, increased compliance obligations and disconnection from the grid.

The regulatory environment for electricity generation in the United States has undergone significant changes in the last several years due to state and federal policies affecting the wholesale and retail power markets and the creation of incentives for the addition of large amounts of new renewable energy generation and demand response resources. These changes are ongoing and we cannot predict the ultimate effect that the changing regulatory environment will have on our business. In addition, in some of these markets, interested parties have proposed material market design changes, as well as made proposals to re-regulate the markets or require divestiture of power generation assets by asset owners or operators to reduce their market share. If competitive restructuring of the power markets is reversed, discontinued or delayed, our business prospects and financial results could be negatively impacted.

The principal revenues generated by our regulated wind and solar assets in Spain are received pursuant to a “regulated return” that is set by legislation. While some of the parameters that go in to calculating the remuneration are subject to periodic review every three and six years, the Spanish legislature ultimately has the power to, as it sees fit, change the regulated return that our Spanish portfolio receives.

Pursuant to Royal Decree 413/2014, renewable electricity producers in Spain receive two principal payment streams: (i) the pool price for the power they produce; and (ii) a return on investment payment based on the standard investment cost for each type of plant (this second payment is not linked to the amount of power they produce). For certain technologies with a high operational expense (including our solar PV and CSP facilities in Spain), the return on investment is supplemented by a return on operations payment. The principle underpinning this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a “reasonable return” on investment (project investment rate of return) over a regulated standard investment cost for each type of plant defined by the government.

In November 2019, the Spanish government issued Royal Decree-Law 17/2019, which set the reasonable return at 7.09% for the next regulatory period (through December 31, 2025) for all assets. However, Royal Decree-Law 17/2019 contained an exception for all plants (i) that were commissioned prior to July 2013 and (ii) that did not have any pending litigation against the Kingdom of Spain regarding the prior regulatory change that took place in July 2013. For these excepted assets, Royal Decree-Law 17/2019 maintained 7.39% as the reasonable return for the next two regulatory periods (through December 31, 2031). As a result, all of our assets in Spain will be entitled to the more favorable regulated rate of 7.39% through December 31, 2031, except for the approximately 45 MW of solar PV assets that we acquired in December 2019 and the approximately 100 MW of CSP assets that we acquired subsequent to year end, each of which are entitled to a reasonable return rate of 7.09% through December 31, 2025.

While the regulated returns that our facilities benefit from currently are favorable to us, it is possible in the future that they will be revised by the legislature in a way that results in a material decrease in the revenues received by our regulated wind

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and solar assets in Spain, which would have an adverse effect on our business, financial condition, results of operations and cash flows.

Revenue from our wind projects in Uruguay is significantly dependent on long-term fixed rate arrangements that restrict our ability to increase revenue from these operations.

In all of our agreements in Uruguay, we have long term PPAs with the Administración Nacional de Usinas y Transmisiones Eléctricas (“UTE”), Uruguay’s state-owned electricity company. Under these PPAs, we are required to deliver power at a fixed rate for the contract period, in all cases inflation adjusted. In addition, during the life of a concession, the relevant government authority may unilaterally impose additional restrictions on our tariff rates, subject to the regulatory frameworks applicable in each jurisdiction. Furthermore, changes in laws and regulations may, in certain cases, have retroactive effect and expose us to additional compliance costs or interfere with our existing financial and business planning.

Laws, governmental regulations and policies supporting renewable energy, and specifically solar and wind energy (including tax incentives), could change at any time, including as a result of new political leadership, and such changes may materially adversely affect our business and our growth strategy.

Renewable energy generation assets currently benefit from, or are affected by, various federal, state and local governmental incentives and regulatory policies. In the United States, these policies include federal ITCs, PTCs, and trade import tariff policies, as well as state RPS and integrated resource plan programs, state and local sales and property taxes, siting policies, grid access policies, rate design, net energy metering, and modified accelerated cost-recovery system of depreciation. The growth of our wind and solar energy business will also be dependent on the federal and state tax and regulatory regimes generally and as they relate in particular to our investments in our wind and solar facilities. For example, future growth in the renewable energy industry in the U.S. will be impacted by the availability of the ITC and PTCs and accelerated depreciation and other changes to the federal income tax codes, including reductions in rates or changes that affect the ability of tax equity providers to effectively obtain the benefit of available tax credits or deductions or forecast their future tax liabilities, which may materially impair the market for tax equity financing for wind and solar power plants. Any effort to overturn federal and state laws, regulations or policies that are supportive of wind and solar power plants or that remove costs or other limitations on other types of generation that compete with wind and solar power plants could materially and adversely affect our business, financial condition, results of operations and cash flows.

In the U.S., many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. If the RPS requirements are reduced or eliminated, it could lead to fewer future power contracts or lead to lower prices for the sale of power in future power contracts, which could have a material adverse effect on our future growth prospects. Such material adverse effects may result from decreased revenues, reduced economic returns on certain project company investments, increased financing costs and/or difficulty obtaining financing.

Our projects located internationally typically benefit from RPS regimes, feed-in tariffs or other regulatory incentives. For example, renewable energy sources in Chile, including our approximately 100 MW solar facility, benefit from an RPS program, and renewable energy sources in Portugal, including our wind assets, benefit from a government regulated feed-in tariff. In Canada, our projects benefit from a long-term power purchase agreement with an entity owned by the government of the province of Ontario. Any adverse change to, or the elimination of, these incentives could have a material adverse effect on our business and our future growth prospects. In Ontario, in December 2019 the government directed the Independent Electricity System Operator of Ontario to solicit feedback from generators on potential cost-lowering opportunities that would reduce electricity rates for consumers while maintaining grid reliability. They indicated that this review might include the triggering of rights within existing power purchase agreements, as well as negotiating changes to existing power purchase agreements, which in either case could have an adverse effect on our business, financial condition, results of operations and cash flows.

We are also subject to laws and regulations that are applicable to business entities generally, including local, state and federal tax laws. As discussed in Government Incentives and Legislation within Item 1. Business, on December 22, 2017, the U.S. government enacted the Tax Act, which contains several provisions that positively and negatively impact our business and operations. If any of the laws or governmental regulations or policies that support renewable energy change, or if we are subject to changes to other existing laws or regulations or new laws or regulation that impact our tax position, increase our compliance costs, are burdensome or otherwise negatively impact our business, such new or changed laws or regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows.

International operations subject us to political and economic uncertainties.

Our portfolio consists of renewable energy facilities located in the United States (including Puerto Rico), Canada, the United Kingdom, Chile, Spain, Portugal and Uruguay. In addition, we could decide to expand our presence in our existing

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international markets or further our expansion into new international markets. As a result, our activities are and will be subject to significant political and economic uncertainties that may adversely affect our operating and financial performance. These uncertainties include, but are not limited to:

•the risk of a change in renewable power pricing policies, possibly with retroactive effect;

•political and economic instability;

•measures restricting the ability of our facilities to access the grid to deliver electricity at certain times or at all;

•the macroeconomic climate and levels of energy consumption in the countries where we have operations;

•the comparative cost of other sources of energy;

•changes in taxation policies and/or the regulatory environment in the countries in which we have operations, including reductions to renewable power incentive programs;

•the imposition of currency controls and foreign exchange rate fluctuations;

•high rates of inflation;

•protectionist and other adverse public policies, including local content requirements, import/export tariffs, increased regulations or capital investment requirements;

•changes to land use regulations and permitting requirements;

•risk of nationalization or other expropriation of private enterprises and land, including creeping regulation that reduces the value of our facilities or governmental incentives associated with renewable energy;

•difficulty in timely identifying, attracting and retaining qualified technical and other personnel;

•difficulty competing against competitors who may have greater financial resources and/or a more effective or established localized business presence;

•difficulties with, and extra-normal costs of, recruiting and retaining local individuals skilled in international business operations;

•difficulty in developing any necessary partnerships with local businesses on commercially acceptable terms; and

•being subject to the jurisdiction of courts other than those of the United States, which courts may be less favorable to us.

In addition, we may be unable to adjust our tariffs or rates as a result of fluctuations in prices above the regulated recognized inflation of raw materials, exchange rates, labor and subcontractor costs, or any other variations in the conditions of specific jurisdictions in which our concession-type infrastructure projects are located, which may reduce our profitability.

These uncertainties, many of which are beyond our control, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may suffer a significant loss resulting from fraud, bribery, corruption, other illegal acts, inadequate or failed internal processes or systems, or from external events.

We may suffer a significant loss resulting from fraud, bribery, corruption, other illegal acts, inadequate or failed internal processes or systems, or from external events, such as security threats affecting our ability to operate. We operate in multiple jurisdictions and it is possible that our operations will expand into new jurisdictions. Doing business in multiple jurisdictions requires us to comply with the laws and regulations of the U.S. government as well as those of various non-U.S. jurisdictions, and the number of jurisdictions in which we are operating has grown in recent years. These laws and regulations may apply to TerraForm Power, Terra LLC, our subsidiaries, our individual directors, officers, employees and third-party contractors and agents. In particular, our non-U.S. operations are subject to U.S. and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (“FCPA”). The FCPA, among other things, prohibits companies and their officers, directors, employees and third-party agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The Company and its officers, directors, employees and third-party agents regularly deal with government bodies and government owned and controlled businesses, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. Also, as we make acquisitions, we may expose ourselves to FCPA or other corruption related risks if our due diligence processes are unable to uncover or detect violations of applicable anti-corruption laws.

We rely on our infrastructure, controls, systems and personnel, to manage the risk of illegal and corrupt acts or failed systems. We also rely on our employees and certain third parties to comply with our policies and processes as well as applicable laws. Specific programs, policies, standards, methodologies and training have been developed to support the management of these risks. However, the failure to adequately identify or manage these risks could result in direct or indirect financial loss, regulatory censure and/or harm to our reputation. The acquisition of businesses with weak internal controls to manage the risk of illegal or corrupt acts may create additional risk of financial loss, regulatory censure and/or harm to our reputation. In addition, programs, policies, standards, methodologies and training, no matter how well designed, do not provide absolute assurance of effectiveness.

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We are subject to environmental, health and safety laws and regulations and related compliance expenditures and liabilities.

Our assets are subject to numerous and significant federal, state, local and foreign laws, and other requirements governing or relating to the environment, health and safety. Our facilities could experience incidents, malfunctions and other unplanned events, such as spills of hazardous materials that may result in personal injury, penalties, property or environmental damage.

Our CSP facilities use regulated thermal “working fluid”, and any leakage of working fluid from storage basins or otherwise could contaminate local groundwater and be hazardous to the environment. In the event of a leak, we are obligated to report it to local authorities and, depending on the severity of the leak, we may also be required to implement certain decontamination measures. If any such leak is not managed adequately and in accordance with applicable regulation, we may be subject to fines or, in extreme cases, have our operating permits revoked. In 2019, we identified leaks at two of our CSP facilities. These leaks are being remediated and as of the date of the Annual Report we are working with our technical advisors and local regulatory authorities to decontaminate the affected soil. While no enforcement action has been taken against us at this time and we do not expect to incur any liability in respect of the current incident, there is no assurance that we will not face liability for these leaks or any future leaks that may occur.

In addition, certain environmental, health and safety laws may result in liability for failure to comply with periodic reporting and other administrative requirements, regardless of fault, concerning contamination at a range of properties, including properties currently or formerly owned, leased or operated by us and properties where we disposed of, or arranged for disposal of, waste and other hazardous materials. In addition, with an increasing global focus and public sensitivity to environmental sustainability and environmental regulation becoming more stringent, we could also be subject to increasing environmental related responsibilities and associated liability. Environmental legislation and permitting requirements may evolve in a manner which will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. As such, the operation of our facilities carries an inherent risk of environmental liability, and may result in our involvement from time to time in administrative and judicial proceedings relating to such matters. These changes may result in increased costs to our operations and may have an adverse impact on prospects for growth of our business. While we have implemented environmental management and health and safety programs designed to continually improve environmental, health and safety performance, there is no assurance that such liabilities including significant required capital expenditures, as well as the costs for complying with environmental laws and regulations, will not have a material adverse effect on our business, financial condition, results of operations and cash flows.

Harming of protected species can result in curtailment of wind power plant operations, monetary fines and negative publicity.

The operation of wind power plants can adversely affect endangered, threatened or otherwise protected animal species, as the turbine blades travel at a high speed and may strike flying animals (such as birds or bats) that happen to travel into the path of spinning blades. Our wind power plants periodically strike and kill flying animals, including, occasionally, endangered or protected species. As a result, we observe industry guidelines and comply with regulator approved incidental take permits and governmentally recommended best practices to avoid harm to such protected species. This includes but is not limited to avoiding erecting structures that could be used as perches, minimizing guy wires that may kill birds or bats in flight, and avoiding lighting that may attract protected species to the wind turbines at night. In addition, we attempt to reduce the attractiveness of a site to predatory birds through regular site maintenance (e.g., mowing and removal of animal and bird carcasses, among other things).

Where possible, we obtain permits for incidental taking of protected species. We hold such permits for some of our wind power plants, particularly in Hawaii, where several species are endangered and protected by law. In addition, we monitor on an ongoing basis U.S. Fish & Wildlife Service and state policy and rulemakings for species relevant to our projects, and will seek permits as appropriate. In 2019, we received approval for amended federal and state incidental take permits for one wind power plant in Hawaii, where, based on standardized monitoring, endangered species mortality exceeded prior estimates and the prior permitted limit on such takings. We are now in full compliance.

Excessive taking of protected species could result in requirements to implement mitigation strategies, including potentially costly modification of operations and/or substantial monetary fines and could also result in negative publicity. For example, our wind power plants in Hawaii are subject to curtailment (i.e., reduction in operations) if excessive taking of protected species is detected through monitoring. Curtailments to protect endangered bats has been implemented at our Hawaiian facilities, but not currently at levels that materially reduce electricity generation or revenues. Such curtailments require, among other things, reduced nighttime operations and also require that operations be limited to times when wind speeds are high enough to prevent bats from flying into a wind power plant’s blades. We cannot guarantee that such curtailments, or

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any monetary fines that are levied or negative publicity that we receive as a result of incidental taking of protected species, will not have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks that are beyond our control, including but not limited to acts of terrorism or acts of war, natural disasters, hostile cyber intrusions, theft or other catastrophic events, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our renewable energy facilities, or those that we otherwise acquire in the future, may be targets of terrorist activities that could cause environmental repercussions and/or result in full or partial disruption of the facilities’ ability to generate electricity. Hostile cyber intrusions, including those targeting information systems as well as electronic control systems used at the facilities and for the related distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as create significant expense to repair security breaches or system damage.

Furthermore, certain of our renewable energy facilities are located in active earthquake zones. The occurrence of a natural disaster, such as an earthquake, hurricane, lightning, flood or localized extended outages of critical utilities or transportation systems, or any critical resource shortages, affecting us could cause a significant interruption in our business, damage or destroy our facilities or those of our suppliers or the manufacturing equipment or inventory of our suppliers.

Additionally, certain of our renewable energy facilities and equipment are at risk for theft and damage. For example, we are at risk for copper wire theft, especially at our solar generation facilities, due to an increased demand for copper in the United States and internationally. Theft of copper wire or solar panels can cause significant disruption to our operations for a period of months and can lead to operating losses at those locations. Damage to wind turbine equipment may also occur, either through natural events such as lightning strikes that damage blades or in-ground electrical systems used to collect electricity from turbines, or through vandalism, such as gunshots into towers or other generating equipment. Such damage can cause disruption of operations for unspecified periods, which may lead to operating losses at those locations.

Other catastrophic events, such as pandemic diseases, may also disrupt our business operations. For example, the recent outbreak of the COVID-19 coronavirus has resulted in closures of manufacturing facilities, travel restrictions, disruptions to supply chains and disruptions to workplaces as employees and contractors cease to be available to perform critical work functions. A prolonged disruption could limit the availability of certain parts required to operate our facilities and adversely impact the ability of our LTSA contractors and other service providers to service our equipment, which may result in operational delays. It could also adversely impact our efforts to repower certain facilities, causing important construction milestones to be missed.

Any such terrorist acts, environmental repercussions or disruptions, natural disasters, theft incidents or other catastrophic events could result in a significant decrease in revenues or significant reconstruction, remediation or replacement costs, beyond what could be recovered through insurance policies, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

A cyberattack or other failure of our communications and technology infrastructure and systems could have a material adverse impact on us.

We rely on information technology systems for secure storage, processing and transmission of sensitive electronic data and other proprietary information for the efficient operation of its renewable energy facilities and corporate operations. In light of this, we may be subject to material cyber security risks or other breaches of information technology security intended to obtain unauthorized access to our proprietary information and that of our business partners, destroy data or disable, degrade, or sabotage these systems through the introduction of computer viruses, fraudulent emails, cyberattacks and other means, and such breaches could originate from a variety of sources including our own employees or unknown third parties. There can be no assurance that measures implemented to protect the integrity of these systems will provide adequate protection, and any such breach could go undetected for an extended period of time. If these information technology systems are impacted by a cyberattack or cyber-intrusion, our operations or capabilities could be interrupted or diminished and important information could be lost, deleted, misused or stolen, which could have a negative impact on our renewable energy facilities, operating results and revenues or which could cause us to incur unanticipated liabilities, reputational damage and regulatory penalties, or incur costs and expenses to repair, replace or enhance affected systems, including costs related to cyber security for our renewable energy facilities and technology systems.

The outbreak of COVID-19 coronavirus could have a material adverse effect on the Company's business, results of operations and financial condition and/or cash flows.

While the impact on our business from the recent outbreak of the COVID-19 coronavirus is unknown at this time and difficult to predict, various aspects of our business could be adversely affected by it. While there are many unknowns as to the

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duration and severity of the COVID-19 coronavirus outbreak, in 2020 as of the date of this Annual Report it has caused significant volatility in global markets, including the market price of our securities. Any prolonged and uncontained outbreak of the COVID-19 coronavirus could result in the imposition of quarantines or closures of office spaces, travel and transportation restrictions and/or import and export restrictions, any of which could contribute to a general slowdown in the global economy, and adversely impact our ability to operate our business and the businesses of our customers and counterparties, any of which could have a materially adverse impact on our business, results of operations and financial condition. In addition, governmental authorities may recommend or impose other measures that could cause significant disruptions to our business operations in the regions most impacted by the coronavirus, including our headquarters in New York City. Any of the foregoing events or other unforeseen consequences of public health problems could materially adversely affect our business, results of operations and financial condition.

Our business is subject to a variety of U.S. and international laws, rules, policies, and other obligations regarding privacy, data protection, and other matters.

We are subject to federal, state, and international laws relating to the collection, use, retention, security, and transfer of customer, employee, and business partner personally identifiable information, including the European Union’s General Data Protection Regulation (“GDPR”), which came into effect in May 2018. In many cases, these laws apply not only to third-party transactions, but also to transfers of information between one company and its subsidiaries, and among the subsidiaries and other parties with which we have commercial relations. The introduction of new products or expansion of our activities in certain jurisdictions may subject us to additional laws and regulations. Foreign data protection, privacy, and other laws and regulations, including GDPR, can be more restrictive than those in the United States. These U.S. federal and state and foreign laws and regulations, including GDPR which can be enforced by private parties or government entities, are constantly evolving and can be subject to significant change. In addition, the application and interpretation of these laws and regulations, including GDPR, are often uncertain, particularly in the new and rapidly evolving industry in which we operate, and may be interpreted and applied inconsistently from country to country and inconsistently with our current policies and practices. These existing and proposed laws and regulations can be costly to comply with and can delay or impede the development of new products, result in negative publicity, increase our operating costs, require significant management time and attention, and subject us to inquiries or investigations, claims or other remedies, including fines, which may be significant, or demands that we modify or cease existing business practices.

A failure by us, our suppliers, or other parties with whom we do business to comply with posted privacy policies or with other federal, state, or international privacy-related or data protection laws and regulations, including GDPR, in effect since May 2018, could result in proceedings against us by governmental entities or others, which could have a material adverse effect on our business, results of operations, and financial condition.

Our use and enjoyment of real property rights for our renewable energy facilities may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to us.

Renewable energy facilities generally are and are likely to be located on land occupied by the facility pursuant to long-term easements and leases. The ownership interests in the land subject to these easements and leases may be subject to mortgages securing loans or other liens (such as tax liens) and other easement and lease rights of third parties (such as leases of oil or mineral rights) that were created prior to the facility’s easements and leases. As a result, the facility’s rights under these easements or leases may be subject, and subordinate, to the rights of those third parties. We perform title searches and obtain title insurance to protect ourselves against these risks. Such measures may, however, be inadequate to protect us against all risk of loss of our rights to use the land on which our renewable energy facilities are located, which could have a material adverse effect on our business, financial condition and results of operations.

Negative public or community response to renewable energy facilities could adversely affect our acquisition of new facilities and the operation of our existing facilities.

Negative public or community response to solar, wind and other renewable energy facilities could adversely affect our ability to acquire and operate our facilities. Our experience is that such opposition subsides over time after renewable energy facilities are completed and are operating, but there are cases where opposition, disputes and even litigation continue into the operating period and could lead to curtailment of a facility’s operations and potentially costly litigation settlements.

The seasonality of our operations may affect our liquidity.

We need to maintain sufficient financial liquidity to absorb the impact of seasonal variations in energy production or other significant events. Our principal sources of liquidity are cash generated from our operating activities, and the cash retained for working capital purposes out of the gross proceeds of financing activities as well as our borrowing capacity under our existing credit facilities, subject to any conditions required to draw under such existing credit facilities. Our results of

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operations may fluctuate significantly for various reasons, mostly related to economic incentives, weather patterns, forced outages (e.g. curtailments or grid related), major unplanned maintenance outages and price fluctuations related to seasonal generation. For instance, the amount of electricity and revenues generated by our solar generation facilities is dependent, in part, on the amount of sunlight, or irradiation where the facilities are located. Due to shorter daylight hours in the winter months which results in less irradiation, the generation produced by these facilities will vary depending on the season. The electricity produced and revenues generated by a wind power plant depend heavily on wind conditions, which are variable and difficult to predict. Operating results for wind power plants vary significantly from period to period depending on the wind conditions during the periods in question.

If we fail to adequately manage the fluctuations in the timing of distributions from our renewable energy facilities, our business, financial condition or results of operations could be materially affected. The seasonality of our energy production may create increased demands on our working capital reserves and borrowing capacity under our existing credit facilities during periods where cash generated from operating activities are lower. In the event that our working capital reserves and borrowing capacity under our existing credit facilities are insufficient to meet our financial requirements, or in the event that the restrictive covenants in our existing credit facilities restrict our access to such facilities, we may require additional equity or debt financing to maintain our solvency. Additional equity or debt financing may not be available when required or available on commercially favorable terms or on terms that are otherwise satisfactory to us, in which event our financial condition may be materially adversely affected.

Risks Related to our Financing Activities

We have incurred substantial indebtedness and may in the future incur additional substantial indebtedness, which may limit our ability to grow our business, reduce our financial flexibility and otherwise may have a material negative impact on our business, results of operations and financial condition.

We have incurred substantial corporate and project-level indebtedness and may incur additional substantial indebtedness in the future. This substantial indebtedness has certain consequences on our business, results of operations and financial condition, including, but not limited to, the following:

•increasing our vulnerability to, and reducing our flexibility to, respond to general adverse economic and industry conditions;

•limiting our flexibility in planning for, or reacting to, changes in our business and the competitive environment and business in which we operate;

•limiting our ability to borrow additional amounts to fund our growth or otherwise meet our obligations;

•limiting our ability to refinance or replace existing indebtedness on favorable terms or at all until the expiration or termination thereof;

•requiring us to dedicate a significant portion of our revenues to pay the principal of and interest on our indebtedness; and

•magnifying the impact of fluctuations in our cash flows on cash available for the payment of distributions to the holders of our Common Stock.

As a result of these consequences, our substantial indebtedness could have a material adverse effect on our business, results of operations and financial condition.

We are subject to operating and financial restrictions through covenants in our corporate and project-level loan, debt and security agreements that may limit our operational activities or limit our ability to raise additional indebtedness.

We are subject to operating and financial restrictions through covenants in our corporate and project-level loan, debt and security agreements. These restrictions prohibit or limit our ability to, among other things, incur additional debt, provide guarantees for indebtedness, grant liens, dispose of assets, liquidate, dissolve, amalgamate, consolidate or effect corporate or capital reorganizations, and declare distributions. A financial covenant in our corporate revolver limits the overall corporate indebtedness that we may incur to a multiple of our cash available for debt service, which may limit our ability to obtain additional financing, withstand downturns in our business and take advantage of business and development opportunities. If we breach our covenants, our corporate Revolver or senior notes may be terminated or come due and such event may cause our credit rating to deteriorate and subject us to higher interest and financing costs. We may also be required to seek additional debt financing on terms that include more restrictive covenants, require repayment on an accelerated schedule or impose other obligations that limit our ability to grow our business, acquire assets or take other actions that we might otherwise consider appropriate or desirable.

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Uncertainty regarding LIBOR may adversely affect the interest we pay under certain of our indebtedness.

In July 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. Currently, it is not possible to predict the exact transitional arrangements for calculating applicable reference rates that may be made in the U.K., the U.S., the Eurozone or elsewhere given that a number of outcomes are possible, including the cessation of the publication of one or more reference rates. To the extent LIBOR is not available, we do not anticipate alternative calculations will be materially different from what would have been calculated under LIBOR. Additionally, no mandatory prepayment or redemption provisions would be triggered under our loan documents in the event that the LIBOR rate is not available. It is possible, however, that any new reference rate that applies to our LIBOR-indexed debt could be different than any new reference rate that applies to our LIBOR-indexed derivative instruments. We anticipate managing this difference and any resulting increased variable-rate exposure through modifications to our debt and/or derivative instruments however, future market conditions may not allow immediate implementation of desired modifications and/or we may incur significant associated costs.

Changes in our credit ratings may have an adverse effect on our financial position and ability to raise capital.

The credit rating assigned to the Company or any of our subsidiaries’ debt securities may be changed or withdrawn entirely by the relevant rating agency. A lowering or withdrawal of such ratings may have an adverse effect on our financial position and ability to raise capital.

Risks Related to our Growth Strategy

The growth of our business depends on locating and acquiring interests in attractive renewable energy facilities at favorable prices and with favorable financing terms. Additionally, even if we consummate such acquisitions and financings on terms that we believe are favorable, such acquisitions may in fact result in a decrease in cash available for distribution per share.

The following factors, among others, could affect the availability of attractive renewable energy facilities to grow our business and distributions per share:

•competing bids for a renewable energy facility;

•fewer third party acquisition opportunities than we expect, including pursuant to existing call rights of the Company;

•risk relating to our ability to successfully acquire ROFO assets from Brookfield and its affiliates; and

•our access to tax equity financing or the capital markets for equity and debt (including project-level debt) at a cost and on terms that would be accretive to our stockholders.

Even if we consummate acquisitions that we believe will be accretive to our distributions per share, those acquisitions may in fact result in a decrease in distributions per share as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences or external events beyond our control.

Our acquisition strategy exposes us to substantial risk.

Our acquisition of renewable energy facilities or of companies that own and operate renewable energy facilities is subject to substantial risk, including but not limited to the failure to identify material problems during due diligence (for which we may not be indemnified post-closing), the risk of over-paying for assets (or not making acquisitions on an accretive basis), the ability to obtain or retain customers and, if the renewable energy facilities are in new markets, the risks of entering markets where we have limited experience. While we perform due diligence on prospective acquisition targets, we may not be able to discover all potential operational deficiencies in such renewable energy facilities. In addition, our expectations for the operating performance of newly constructed renewable energy facilities as well as those under construction may be based on assumptions and estimates made without the benefit of operating history. However, the ability of these renewable energy facilities to meet our performance expectations is subject to the risks inherent in newly constructed renewable energy facilities and the construction of such facilities, including, but not limited to, degradation of equipment in excess of our expectations, system failures and outages. Future acquisitions may not perform as expected or the returns from such acquisitions may not support the financing utilized to acquire them or maintain them. Furthermore, integration and consolidation of acquisitions requires substantial human, financial and other resources and may divert management’s attention from our existing business concerns and any such integration may not be successful. As a result, the consummation of acquisitions could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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We may not be able to effectively identify or consummate any future acquisitions. Additionally, even if we consummate acquisitions, such acquisitions may in fact result in a decrease in cash available for distribution. In addition, we may engage in asset dispositions or other transactions that result in a decrease in our cash available for distribution.

Future acquisition opportunities for renewable energy facilities are limited and there is substantial competition for the acquisition of these assets. Moreover, while Brookfield and its affiliates will grant us a ROFO with respect to the projects in the right of first offer portfolio as a result of the Merger and Sponsorship Transaction, there is no assurance that we will be able to acquire or successfully integrate any such projects. We will compete with other companies for future acquisition opportunities from Brookfield and its affiliates and third parties.

Competition for acquisitions may increase our cost of making acquisitions or cause us to refrain from making acquisitions at all. Some of our competitors are much larger than us with substantially greater resources, have access to lower costs of capital, or have lower return targets. These companies may be able to pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets than our resources, costs of capital or return targets permit. In addition, our competitors may be to make acquisitions for renewable energy facilities having less desirable economic returns or higher risk profiles than we believe suitable for our business plan and investment strategy. If we are unable to identify and consummate future acquisitions, it will impede our ability to execute our growth strategy and limit our ability to increase the amount of distributions paid to holders of our Common Stock. In addition, as we continue to manage our liquidity profile, we may engage in asset dispositions, or incur additional project-level debt, which may result in a decrease in our CAFD. Even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact result in a decrease in CAFD as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences or other external events beyond our control. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and stockholders will generally not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Certain assets are owned, or in the future may be acquired, alongside minority investors who are entitled to influence certain management decisions and our interests and those of any such minority investors may differ.

We own certain assets alongside minority investors, in which we do not have complete control over management decisions as a result of the agreements governing such investments. For example, minority investor approval may be required for us to receive distributions of funds from these assets or to sell, pledge, transfer, assign or otherwise convey our interest in such assets. Alternatively, our minority investors may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of our interests in such assets. The interests of any minority investor may not be aligned with ours and they may seek to exercise consent rights that may inhibit our ability to manage the asset as we see fit. As we look to from time to time recycle capital, we may deem it advisable to opportunistically sell a minority interest in one or more assets, and such new minority investors may negotiate consent rights or other governance arrangements that restrict our ability to control all management decisions in respect of such assets.

Our ability to grow and make acquisitions with cash on hand may be limited by our cash distribution policy.

In the future, we intend to pay distributions to our stockholders each quarter and to rely primarily upon external financing sources, including the issuance of debt and equity securities to fund our acquisitions and growth capital expenditures. We may be precluded from pursuing otherwise attractive acquisitions if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund the acquisition or investment. As such, our growth may not be as fast as that of businesses that reinvest more available cash from operations.

We may not have access to all operating wind and solar acquisitions that Brookfield identifies.

Our ability to grow through acquisitions depends on Brookfield’s ability to identify and present us with acquisition opportunities. Brookfield has designated TerraForm Power, subject to certain exceptions, as its primary vehicle to acquire operating wind and solar assets in North America and Western Europe. However, Brookfield’s obligations to the Company under the Relationship Agreement are subject to a number of exceptions and Brookfield has no obligation to source acquisition opportunities specifically for us. There are a number of factors which could materially and adversely impact the extent to which suitable acquisition opportunities are made available to us by Brookfield, for example:

•It is an integral part of Brookfield’s strategy to pursue the acquisition or development of renewable power assets through consortium arrangements with institutional investors, strategic partners and/or financial sponsors and to form partnerships (including private funds, joint ventures and similar arrangements) to pursue acquisitions on a specialized basis. In certain circumstances, acquisitions of operating wind and solar assets in our primary jurisdictions may be made by other Brookfield vehicles, either with or instead of us.

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•The same professionals within Brookfield’s organization that are involved in sourcing acquisitions that are suitable for us are often responsible for sourcing opportunities for vehicles, consortiums and partnerships referred to above, as well as having other responsibilities within Brookfield’s broader asset management business. Limits on the availability of such individuals will likewise result in a limitation on the availability of acquisition opportunities for us.

•Brookfield will only recommend acquisition opportunities that it believes are suitable and appropriate for us. The question of whether a particular acquisition is suitable and appropriate is highly subjective and is dependent on a number of factors including an assessment by Brookfield of our liquidity position, the risk and return profile of the opportunity, and other factors. If Brookfield determines that an opportunity is not suitable or appropriate for us, it may still pursue such opportunity on its own behalf, or on behalf of a Brookfield-sponsored vehicle.

Our ability to raise additional capital to fund our operations and growth may be limited.

We may need to arrange additional financing to fund all or a portion of the cost of acquisitions, including potential contingent liabilities and other aspects of our operations. Our ability to arrange additional financing or otherwise access the debt or equity capital markets, either at the corporate-level or at a non-recourse project-level subsidiary, may be limited. Any limitations on our ability to obtain financing may have an adverse effect on our business, or growth prospects or our results of operations. Additional financing, including the costs of such financing, will be dependent on numerous factors, including:

•general economic and capital market conditions, including the then-prevailing interest rate environment;

•credit availability from banks and other financial institutions;

•investor confidence in us, our partners, our Sponsor, and the regional wholesale power markets;

•our financial performance and the financial performance of our subsidiaries;

•our level of indebtedness and compliance with covenants in debt agreements;

•our ability to file SEC reports on a timely basis and obtain audited project-level financial statements;

•maintenance of acceptable credit ratings or credit quality, including maintenance of the legal and tax structure of the project-level subsidiary upon which the credit ratings may depend;

•our cash flows; and

•provisions of tax and securities laws that may impact raising capital.

We may not be successful in obtaining additional financing for these or other reasons. Furthermore, we may be unable to refinance or replace non-recourse financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. Our failure, or the failure of any of our renewable energy facilities, to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Inherent in an Investment in TerraForm Power, Inc.

We may not be able to pay cash distributions to holders of our Common Stock in the future.

The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•our ability to realize the expected benefits from Brookfield’s sponsorship on our business and results of operations;

•the timing of our ability to complete our audited corporate and project-level financial statements;

•risks related to our ability to file our annual and quarterly reports with the SEC on a timely basis and to satisfy the requirements of the Nasdaq Global Select Market (“Nasdaq”);

•our ability to integrate acquired assets and realize the anticipated benefits of these acquired assets;

•The willingness and ability of the counterparties to our offtake agreements to fulfill their obligations under such agreements;

•price fluctuations, termination provisions and buyout provisions related to our offtake agreements;

•our ability to enter into contracts to sell power on acceptable terms as our offtake agreements expire;

•delays or unexpected costs during the completion of construction of certain renewable energy facilities we intend to acquire;

•our ability to successfully identify, evaluate and consummate acquisitions;

•government regulation, including compliance with regulatory and permit requirements and changes in market rules, rates, tariffs, tax law, environmental laws and political climate;

•operating and financial restrictions placed on us and our subsidiaries related to agreements governing our indebtedness and other agreements of certain of our subsidiaries and project-level subsidiaries generally;

•our ability to borrow additional funds and access capital markets on favorable terms or at all, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;

•our ability to compete against traditional and renewable energy companies;

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•hazards customary to the power production industry and power generation operations such as unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, interconnection problems or other developments, environmental incidents, or electric transmission constraints and the possibility that we may not have adequate insurance to cover losses as a result of such hazards;

•our ability to expand into new business segments or new geographies;

•seasonal variations in the amount of electricity our wind and solar plants produce, and fluctuations in wind and solar resource conditions; and

•our ability to operate our businesses efficiently, manage capital expenditures and costs tightly, manage litigation, manage risks related to international operations and generate earnings and cash flow from our asset-based businesses in relation to our debt and other obligations.

As a result of all these factors, we cannot guarantee that we will have sufficient cash generated from operations to pay a specific level of cash distributions to holders of our Common Stock. Furthermore, holders of our Common Stock should be aware that the amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay distributions to holders of our Common Stock during the period. We are a holding company and our ability to pay distributions on our Common Stock is limited by restrictions on the ability of our subsidiaries to pay distributions or make other distributions to us, including restrictions under the terms of the agreements governing project-level financing. Our project-level financing agreements prohibit distributions to us unless certain specific conditions are met, including the satisfaction of financial ratios and the absence of payment or covenant defaults.

Furthermore, we have issued additional equity securities from time to time, including in connection with our acquisition of our European Platform and for general corporate purposes, and we may issue additional equity securities in the future. The payment of distributions on these additional equity securities may increase the risk that we will be unable to maintain or increase our per share distribution. There are no limitations in our amended and restated certificate of incorporation (other than a specified number of authorized shares) on our ability to issue equity securities, including securities ranking senior to our Common Stock. The incurrence of bank borrowings or other debt by Terra Operating LLC or by our project-level subsidiaries to finance our growth strategy will result in increased interest expense and the imposition of additional or more restrictive covenants which, in turn, may impact the cash distributions we distribute to holders of our Common Stock.

Finally, distributions to holders of our Common Stock will be paid at the discretion of our Board.

Our payout ratio has recently exceeded our long-term target and, in some periods, our CAFD. If this were to continue, it could impact our ability to maintain or grow our distributions.

Our payout ratio is a measure of our ability to make cash distributions to stockholders. We target a long-term payout ratio of 80 to 85% of CAFD. From time to time, our payout ratio may exceed 100%, for example, during periods of lower generation or lower merchant power prices or combination thereof, or repowering or operational maintenance investment periods. Because our business is primarily dependent on generation conditions and merchant power prices, as well as other factors beyond our control, it is possible that our payout ratio may remain above 100% for a sustained period. If this were to occur, it could impact our ability to maintain or grow our distributions to stockholders in line with our stated targets.

Certain of our stockholders have accumulated large concentrations of holdings of our Common Stock, which among other things, may impact the liquidity of our Common Stock.

In addition to Brookfield, certain of our stockholders hold large positions in our Common Stock and new or existing stockholders may accumulate large positions in our Common Stock, which may impact the liquidity of shares of our Common Stock. In the event that stockholders hold these large positions in shares of our Common Stock not owned by Brookfield this concentration of ownership may reduce the liquidity of our Common Stock and may also have the effect of delaying or preventing a future change in control of our company or discouraging others from making tender offers for our shares, which could depress the price per share a bidder might otherwise be willing to pay.

We are a holding company and our primary asset is our direct and indirect interest in Terra LLC, and we are accordingly dependent upon distributions from Terra LLC and its subsidiaries to pay distributions and taxes and other expenses.

TerraForm Power is a holding company and has no material assets other than its direct and indirect ownership of membership interests in Terra LLC, a holding company that has no material assets other than its interest in Terra Operating LLC, whose sole material assets are interests in holding companies that directly or indirectly own the renewable energy facilities that comprise our portfolio and the renewable energy facilities that we subsequently acquire. TerraForm Power, Terra LLC and Terra Operating LLC have no independent means of generating revenue. We intend to cause Terra Operating LLC’s

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subsidiaries to make distributions to Terra Operating LLC and, in turn, make distributions to Terra LLC, and, Terra LLC, in turn, to make distributions to TerraForm Power in an amount sufficient to cover all applicable taxes payable and distributions, if any, declared by us. To the extent that we need funds to pay a quarterly cash distribution to holders of our Common Stock or otherwise, and Terra Operating LLC or Terra LLC is restricted from making such distributions under applicable law or regulation or is otherwise unable to provide such funds (including as a result of Terra Operating LLC’s operating subsidiaries being unable to make distributions, such as due to defaults in project-level financing agreements), it could materially adversely affect our liquidity and financial condition and limit our ability to pay distributions to holders of our Common Stock.

Market interest rates may have an effect on the value of our Common Stock.

One of the factors that influences the price of shares of our Common Stock will be the effective distribution yield of such shares (i.e., the yield as a percentage of the then market price of our shares) relative to market interest rates. An increase in market interest rates may lead prospective purchasers of shares of our Common Stock to expect a higher distribution yield. If market interest rates increase and we are unable to increase our distribution in response, including due to an increase in borrowing costs, insufficient cash available for distribution or otherwise, investors may seek alternative investments with higher yield, which would result in selling pressure on, and a decrease in the market price of, our Common Stock. As a result, the price of our Common Stock may decrease as market interest rates increase.

The market price and marketability of our shares may from time to time be significantly affected by numerous factors beyond our control, which may adversely affect our ability to raise capital through future equity financings.

The market price of our shares may fluctuate significantly. Many factors may significantly affect the market price and marketability of our shares and may adversely affect our ability to raise capital through equity financings and otherwise materially adversely impact our business. These factors include, but are not limited to, the following:

•price and volume fluctuations in the stock markets generally;

•significant volatility in the market price and trading volume of securities of registered investment companies, business development companies or companies in our sectors, which may not be related to the operating performance of these companies;

•changes in our earnings or variations in operating results;

•changes in regulatory policies or tax law;

•operating performance of companies comparable to us; and

•loss of funding sources or the ability to finance or refinance our obligations as they come due.

Investors may experience dilution of their ownership interest due to the future issuance of additional shares of our Common Stock.

We are in a capital intensive business, and may not have sufficient funds to finance the growth of our business, acquisitions or to support our projected capital expenditures. As a result, we have engaged in, and may require additional funds from further, equity or debt financings, including tax equity financing transactions or sales of preferred shares or convertible debt to complete future acquisitions, expansions and capital expenditures and pay the general and administrative costs of our business. In the future, we may issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of purchasers of our Common Stock offered hereby. Under our amended and restated certificate of incorporation, we are authorized to issue 1,200,000,000 shares of Common Stock and 100,000,000 shares of preferred stock with preferences and rights as determined by our Board. The potential issuance of additional shares of Common Stock or preferred stock or convertible debt may create downward pressure on the trading price of our Common Stock. We may also issue additional shares of our Common Stock or other securities that are convertible into or exercisable for our Common Stock in future public offerings or private placements for capital raising purposes or for other business purposes, potentially at an offering price, conversion price or exercise price that is below the trading price of our Common Stock.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business or our market, or if they change their recommendations regarding our Common Stock adversely, the stock price and trading volume of our Common Stock could decline.

The trading market for our Common Stock will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market or our competitors. If any of the analysts who may cover us change their recommendation regarding our Common Stock adversely, or provide more favorable relative recommendations about our competitors, the price of our Common Stock would likely decline. If any analyst who may cover us were to cease coverage of our company or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause the stock price or trading volume of our Common Stock to decline.

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The settlement of certain existing litigation will trigger a requirement to issue additional Common Stock to Brookfield.

We have agreed pursuant to the Merger and Sponsorship Transaction agreement dated March 6, 2017 among the Company, Orion Holdings and BRE TERP Holdings Inc., to issue additional shares of Common Stock to Brookfield for no additional consideration in respect of the final resolution of certain specified litigation (see Note 20. Commitments and Contingencies to our consolidated financial statements for a description of such litigation). The number of additional shares of Common Stock to be issued to Brookfield is subject to a pre-determined formula as set forth in the Merger Agreement as described in greater detail in the Company’s Definitive Proxy Statement filed on Schedule 14A with the SEC on September 6, 2017 and will compensate Brookfield for the total amount of losses we incur with respect to such specified litigation. Any shares of Common Stock issued to Brookfield would result in the dilution of the ownership interests of our remaining Class A common stockholders.

Our failure to achieve and maintain effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and share price.

We are required to comply with Section 404(a) of the Sarbanes-Oxley Act in the course of preparing our financial statements, and our management is required to report on the effectiveness of our internal control over financial reporting for such year. Additionally, our independent registered public accounting firm is required pursuant to Section 404(b) of the Sarbanes-Oxley Act to attest to the effectiveness of our internal control over financial reporting on an annual basis. The rules governing the standards that must be met for our management to assess our internal control over financial reporting are complex and require significant documentation, testing and possible remediation.

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with U.S. GAAP. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented or detected on a timely basis. The existence of any material weakness would require management to devote significant time and incur significant expense to remediate any such material weaknesses and management may not be able to remediate any such material weaknesses in a timely manner.

As of December 31, 2019, we did not maintain an effective control environment attributable to certain identified material weaknesses. We describe these material weaknesses in Item 9A. Controls and Procedures in this Annual Report. These control deficiencies create a reasonable possibility that a material misstatement to the consolidated financial statements will not be prevented or detected on a timely basis, and therefore we concluded that the deficiencies represent material weaknesses in our internal control over financial reporting and our internal control over financial reporting was not effective as of December 31, 2019.

The existence of these or other material weaknesses in our internal control over financial reporting could also result in errors in our financial statements that could require us to restate our financial statements, cause us to fail to meet our reporting obligations and cause stockholders to lose confidence in our reported financial information, all of which could materially and adversely affect our business and stock price.

A significant portion of our assets consists of long-lived assets, the value of which may be reduced if we determine that those assets are impaired.

As of December 31, 2019, the net carrying value of long-lived assets represented $9.3 billion, or 93%, of our total assets and consisted of renewable energy facilities, intangible assets and goodwill from the acquisition of Saeta. Renewable energy facilities and intangible assets are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value.

Goodwill is reviewed for impairment at least annually and whenever facts and circumstances indicate that it is more-likely-than-not that the fair value of a reporting unit that has goodwill is less than its carrying value. An impairment loss is recognized if the fair value of a reporting unit is less than its carrying value. As of December 1, 2019, we performed a qualitative impairment test for the goodwill balance in Saeta of $128.0 million and determined that it is more-likely-than-not that the fair values of the reporting units exceed their carrying amounts. We concluded that further evaluation of impairment was not necessary and goodwill associated with the Saeta acquisition was not impaired at December 31, 2019.

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Risks Related to our Relationship with Brookfield

We may not realize the expected benefits of Brookfield sponsorship.

TerraForm Power and Brookfield are party to certain sponsorship agreements, which include, among other things, for Brookfield to provide strategic and investment management services to us, for Brookfield, subject to certain terms and conditions, to provide us with a right of first offer on certain operating wind and solar assets that are located in North America and Western Europe and developed by persons sponsored by or under the control of Brookfield and for Brookfield to provide TerraForm Power with a $500 million secured revolving credit facility to fund certain acquisitions or growth capital expenditures.

We may not realize expected benefits of Brookfield’s management services and the other aspects of the sponsorship arrangements. For example, we may fail to realize expected operational or margin improvements, synergies or other cost savings or reductions, may not achieve expected growth in its portfolio through organic growth or third-party acquisitions and may not acquire assets from Brookfield. We may also not be able to effectively utilize the $500 million revolving credit facility provided by Brookfield for accretive acquisitions or at all. Our failure to realize these aspects of Brookfield sponsorship may have an adverse effect on the price of our Common Stock and on our business, growth and the results of our operations.

We are a “controlled company” controlled by Brookfield, whose interest in our business may be different from our interests or the interests of other holders of our Common Stock.

Brookfield owns an approximate 62% interest in TerraForm Power. Pursuant to the terms of the New Terra LLC Agreement (as defined herein), Brookfield is also entitled to IDRs. Cash distributions from Terra LLC are allocated between the holders of the Class A units in Terra LLC and the holders of the IDRs according to a fixed formula. In addition, pursuant to the terms of the Brookfield MSA, Brookfield is entitled to certain fixed and variable management fees for services performed for the Company. As a result of these economic rights, Brookfield may have interests in our business that are different from our interests or the interests of the other holders of our Common Stock.

In addition, pursuant to the Merger Agreement, if there has been a final resolution of certain specified litigation involving the Company, we have agreed to issue a number of additional Class A shares to Brookfield for no additional consideration based on the amounts paid or accrued by us or any of our affiliates, including Brookfield, with respect to such litigation, calculated in accordance with specified formulas. As a result of this arrangement, Brookfield may have interests in the specified litigation that is different from our interests or the interests of the other holders of our Common Stock.

Brookfield currently owns interests in, manages and controls, and may in the future own or acquire interests in, manage and/or control, other yield focused publicly listed and private electric power businesses that own clean energy assets and other public and private businesses that own and invest in other real property and infrastructure assets. Brookfield may have conflicts or potential conflicts, including resulting from the operation by Brookfield of its other businesses, including its other yield focused electric power businesses, including with respect to Brookfield’s attention to and management of our business which may be negatively affected by Brookfield’s ownership and/or management of other power businesses and other public and private businesses that it owns, controls or manages.

For so long as Brookfield or another entity controls greater than 50% of the total outstanding voting power of our Common Stock, we will be considered a “controlled company” for the purposes of the Nasdaq listing requirements. As a “controlled company,” we are permitted to opt out of the Nasdaq listing requirements that require (i) a majority of the members of our Board to be independent, (ii) that we establish a compensation committee and a nominating and governance committee, each comprised entirely of independent directors, and (iii) an annual performance evaluation of the nominating and governance and compensation committees. We expect to rely on such exceptions with respect to having a majority of independent directors, establishing a compensation committee or nominating committee and annual performance evaluations of such committees. Brookfield may sell part or all of its stake in the Company, or may have its interest in the Company diluted due to future equity issuances, in each case, which could result in a loss of the “controlled company” exemption under the Nasdaq rules. We would then be required to comply with those provisions of the Nasdaq listing requirements on which we currently or in the future may rely upon exemptions.

Brookfield and its affiliates control the Company and have the ability to designate a majority of the members of our Board.

Pursuant to the governance agreements entered into between the Company and Brookfield, Brookfield has the ability to designate a majority of our Board to our Nominating and Corporate Governance Committee for nomination for election by our stockholders. Due to such agreements, and Brookfield’s approximate 62% interest in the Company, the ability of other holders of our Common Stock to exercise control over the corporate governance of the Company will be limited. In addition, due to its approximate 62% interest in the Company, Brookfield has a substantial influence on our affairs and its voting power

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constitutes a large percentage of any quorum of our stockholders voting on any matter requiring the approval of our stockholders. As discussed in the risk factor entitled “We are a “controlled company” controlled by Brookfield and its affiliates, whose interest in our business may be different from ours or other holders of our Common Stock.” above, Brookfield may hold certain interests that are different from ours or other holders of our Common Stock and there is no assurance that Brookfield will exercise its control over the Company in a manner that is consistent with our interests or those of the other holders of our Common Stock.

Brookfield’s sponsorship may create significant conflicts of interest that may be resolved in a manner that is not in our best interest or the best interest of our stockholders.

Our sponsorship arrangements with Brookfield involve relationships that may give rise to conflicts of interest between us and our stockholders, on the one hand, and Brookfield, on the other hand. We rely on Brookfield to provide us with, among other things, strategic and investment management services. Although our sponsorship arrangements require Brookfield to provide us with a Chief Executive Officer, Chief Financial Officer and General Counsel who are dedicated to us on a full-time basis and have as their primary responsibility the provision of services to us, there is no requirement for Brookfield to act exclusively for us or for Brookfield to provide any specific individuals to us on an ongoing basis.

In certain instances, the interests of Brookfield may differ from our interests, including among other things with respect to the types of acquisitions we pursue, the timing and amount of distributions we make, the reinvestment of returns generated by our operations, the use of leverage when making acquisitions and the appointment of certain outside advisers and service providers. Although we believe the requirement for our Conflicts Committee to review and approve any potential conflict transactions between us and Brookfield should mitigate this risk, there can be no assurance that such review and approvals will result in a resolution that is entirely in our best interests or the best interests of our stockholders.

Brookfield exercises substantial influence over the Company and we are highly dependent on Brookfield.

We depend on the management and administration services provided by Brookfield pursuant to the Brookfield MSA. Other than our Chief Executive Officer, Chief Financial Officer and General Counsel, Brookfield personnel and support staff that provide services to us under the Brookfield MSA are not required to have as their primary responsibility the management and administration of us or to act exclusively for us and the Brookfield MSA does not require any specific individuals to be provided to us. Failing to effectively manage our current operations or to implement our strategy could have a material adverse effect on our business, financial condition and results of operations.

The departure of some or all of Brookfield’s professionals could prevent us from achieving our objectives.

We depend on the diligence, skill and business contacts of Brookfield’s professionals and the information and opportunities they generate during the normal course of their activities. Our future success will depend on the continued service of these individuals, who are not obligated to remain employed with Brookfield. Brookfield has experienced departures of key professionals in the past and may experience departures again in the future, and we cannot predict the impact that any such departures will have on our ability to achieve our objectives. The departure of a significant number of Brookfield’s professionals for any reason, or the failure to appoint qualified or effective successors in the event of such departures, could have a material adverse effect on our ability to achieve our objectives.

The role of Brookfield, and the relative amount of the Company’s Common Stock that it controls, may change.

Our arrangements with Brookfield do not require Brookfield to maintain any ownership level in the Company. If Brookfield decides to sell part or all of its stake in the Company, or has its interest in the Company diluted due to future equity issuances, we could lose the benefit of the “controlled company” exemption for the purposes of the Nasdaq rules as discussed in the risk factor entitled “We are a “controlled company” controlled by Brookfield, whose interest in our business may be different from ours or other holders of our Class A common stock.” Additionally, if Brookfield’s ownership interest falls below 25%, we would have the right to terminate the Brookfield MSA. Any decision by us to terminate the Brookfield MSA would trigger a termination of the Relationship Agreement. As a result, we cannot predict with any certainty the effect that any change in Brookfield’s ownership would have on the trading price of our shares or our ability to raise capital or make investments in the future.

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Other Risks

If we are deemed to be an investment company, we may be required to institute burdensome compliance requirements and our activities may be restricted, which may make it difficult for us to complete strategic acquisitions or affect combinations.

If we are deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”) our business would be subject to applicable restrictions under the Investment Company Act, which could make it impractical for us to continue our business as contemplated. We believe our company is not an investment company under Section 3(b)(1) of the Investment Company Act because we are primarily engaged in a non-investment company business, and we intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated.

Potential future delays in the filing of our reports with the SEC, as well as further delays in the preparation of audited financial statements at the project level, could have a material adverse effect.

In the past, we were not timely in filing certain of our quarterly reports on Form 10-Q and annual reports on Form 10-K with the SEC. During the period of these delays, we received notification letters from Nasdaq that granted extensions to regain compliance with Nasdaq’s continued listing requirements, subject to the requirement that we file our SEC reports and hold our annual meeting of stockholders by certain deadlines. While we are now current in our filing of periodic reports under the Exchange Act and are in compliance with Nasdaq’s continued listing requirements, in the event that any future periodic report is delayed, there is no assurance that we will be able to obtain further extensions from Nasdaq to maintain or regain compliance with Nasdaq’s continued listing requirements with respect to any such delayed periodic report. If we fail to obtain any such further extensions from Nasdaq, our Common Stock would likely be delisted from the Nasdaq.

The delay in filing our annual reports on Form 10-K and our Quarterly Reports on Form 10-Q and related financial statements has at times impaired our ability to obtain financing and access the capital markets, and to the extent we fail to make timely filings in the future, our access to financing may be impaired. For example, the delayed filing of our periodic reports with the SEC beyond available grace periods would result in the Company losing its eligibility to register the offer and sale of our securities using a short-form registration statement on Form S-3. Additional delays may also negatively impact our ability to obtain project financing and our ability to obtain waivers or forbearances to the extent of any defaults or breaches of project-level financing. An inability to obtaining financing may have a material adverse effect on our ability to grow our business, acquire assets through acquisitions or optimize our portfolio and capital structure. Additionally, a delay in audited financial statements may make our Board less comfortable with approving the payment of distributions.

Financial statements at the project-level were also delayed over the course of 2016, 2017 and 2018. This delay created defaults under certain of our non-recourse financing agreements, which have been substantially cured or waived as of the date hereof. To the extent any remaining defaults remain uncured or unwaived, or new defaults arise because of future delays in the completion of audited or unaudited financial statements, our subsidiaries may be restricted in their the ability to make distributions to us, or the related lenders may be entitled to demand repayment or enforce their security interests, which could have a material adverse effect on our business, results of operations, financial condition, our ability to pay dividends and our ability to comply with corporate-level debt covenants.

Taxation Risks

Changes in tax law and practice may have a material adverse effect on the operations of TerraForm Power, the Holding Entities, and the Operating Entities and, as a consequence, the value of TerraForm’s assets.

The TerraForm Power structure, including the structure of the Holding Entities and the Operating Entities, is based on prevailing taxation law and practice in the local jurisdictions (such as Canada, Chile, Spain, Portugal, Puerto Rico, the United States, the United Kingdom and Uruguay) in which the TerraForm Power entities operate. TerraForm Power’s provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits, including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit carryforwards, such as net operating loss and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to the future impacts of, among other things, changes in tax laws, guidance or policies, including changes in corporate income tax rates, the financial condition and results of operations of TerraForm Power, and the resolution of audit issues raised by taxing authorities. These factors, including the ultimate resolution of income tax matters, may result in material adjustments to tax-related assets and liabilities, which could materially adversely affect TerraForm Power’s business, financial condition, results of operations and prospects.

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Our future tax liability may be greater than expected if we do not generate NOLs sufficient to offset taxable income or if tax authorities challenge certain of our tax positions.

We are subject to U.S. federal income tax at regular corporate rates on our net taxable income. We expect to generate NOL carryforwards that we can use to offset future taxable income. As a result, we do not expect to pay meaningful U.S. federal income tax in the foreseeable future. This estimate is based upon assumptions we have made regarding, among other things, our income, capital expenditures, cash flows, net working capital and cash distributions. Furthermore, the Internal Revenue Service (“IRS”) or other tax authorities could challenge one or more tax positions we take, such as the classification of assets under the income tax depreciation rules, the characterization of expenses for income tax purposes, the extent to which sales, use or goods and services tax applies to operations in a particular state or the availability of property tax exemptions with respect to our projects. Furthermore, any change in tax law may affect our tax position, including changes in corporate income tax laws, regulations and policies applicable to us. While we expect that our NOLs and NOL carryforwards will be available to us as a future benefit, in the event that they are not generated as expected, are successfully challenged by the IRS (in a tax audit or otherwise) or are subject to future limitations as described below, our ability to realize these benefits may be limited.

Our ability to use NOLs to offset future income may be limited.

Our ability to use federal NOLs to offset future taxable income are limited under Internal Revenue Code Section 382. Any NOLs that exceed this yearly limitation may be carried forward and used to offset taxable income for the remainder of the carryforward period (i.e., 20 years from the year in which such NOL was generated for NOLs generated prior to January 1, 2018 and no carryforward limitation for any subsequently generated NOLs).

Distributions to stockholders may be taxable as distributions.

If we make distributions from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions will generally be taxable to stockholders as ordinary distribution income for U.S. federal income tax purposes. Distributions paid to non-corporate U.S. stockholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. However, it is difficult to predict whether we will generate earnings and profits as computed for U.S. federal income tax purposes in any given tax year, and although we expect that distributions to stockholders may exceed the current and accumulated earnings and profits as computed for U.S. federal income tax purposes and therefore constitute a non-taxable return of capital distribution to the extent of a stockholder’s basis in its shares, this may not occur. In addition, although return-of-capital distributions are generally non-taxable to the extent of a stockholder’s basis in its shares, such distributions will reduce the stockholder’s adjusted tax basis in our shares, which will result in an increase in the amount of gain (or a decrease in the amount of loss) that will be recognized by the stockholder on a future disposition of our shares, and to the extent any return-of-capital distribution exceeds a stockholder’s basis, such distributions will be treated as gain on the sale or exchange of the shares.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our current portfolio consists of distributed generation facilities and utility-scale power plants located in the United States (including Puerto Rico), Canada, the United Kingdom, Spain, Portugal, Uruguay, and Chile, with a combined nameplate capacity of over 4,100 MW as of December 31, 2019. We have financed certain of our assets through project-specific debt secured by the project’s assets (mainly the renewable energy facilities) or equity interests in such renewable energy facilities with no recourse to Terra LLC or Terra Operating LLC. See the table of our properties in Item 1. Business - Our Portfolio.

Distributed generation facilities

Our distributed generation facilities provide customers with an alternative to traditional utility energy suppliers. Distributed resources are typically smaller in unit size and can be installed at a customer’s site, removing the need for lengthy transmission and distribution lines. By bypassing the traditional utility suppliers, distributed energy systems delink the customer’s price of power from external factors such as volatile commodity prices, costs of the incumbent energy supplier, and certain transmission and distribution charges. This makes it possible for distributed energy purchasers to buy energy at a predictable and stable price over a long period of time.

Certain PPAs for our distributed generation facilities located in the United States allow the offtake purchaser to elect to purchase the facility from us at a price equal to the greater of a specified amount in the PPA or fair market value. In addition,

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certain of our PPAs allow the offtake purchaser to terminate the PPA if we do not meet certain prescribed operating thresholds or performance measures or otherwise by the payment of an early termination fee, which would require us to remove the renewable energy facility from the offtake purchaser’s site. These operating thresholds and performance measures are readily achievable in the normal operation of renewable energy facilities.

Utility-scale wind and solar facilities

Our utility-scale solar and wind generation facilities are larger scale power plants for which the purchaser of the electricity is an electric utility, governmental entity or other third party or where the power is delivered directly to the grid. Our utility scale solar facilities are typically ground mounted PV systems. The systems use either thin film, monocrystalline or polycrystalline PV modules that are attached to either fixed tilt racking or mounted on single axis (one direction) trackers, which allow the modules to track the sun as it moves throughout the day. The modules absorb direct and reflected sunlight to create electrical energy. Electrical energy is generated in direct current or DC and then converted to alternating current or AC using an inverter. The inverters are connected to a medium voltage power collection system that feeds into a substation, which increases the voltage further for interconnection with the existing electrical transmission system.

Our utility scale wind facilities consist of groupings of wind turbine generators spaced over a contiguous area. The wind turbine generators have three main sections, the rotor, nacelle, and tower. The rotor has three blades affixed to the hub at 120 degrees from each other. The nacelle houses the generator and gearbox and is attached to the hub through the main shaft at the front of the nacelle and the tower through the yaw drive at the bedplate of the nacelle. As wind turns the rotor, the main shaft turns the gearbox to increase the speed and turn the generator. The generator creates AC electrical energy. These turbines are connected via a medium voltage power collection system that feeds into one or more substations that are used to increase the voltage before transmitting the energy generated to the high voltage transmission system.

Concentrated solar power

Solar thermal technology at our CSP facilities uses different mirrors and reflector configurations to transform the sun’s energy into high-temperature heat that can then be converted into usable forms of energy. When light rays travel parallel to the axis of a spherical mirror, they are reflected and converge in the focus of that spherical mirror. As all the different light rays converge in a single point, their light energy is concentrated on it, heating a fluid that produces steam to feed a steam cycle that produces electricity. Solar thermal technology requires a high level of direct solar irradiation to be feasible.

Solar thermal power is a more sophisticated technology compared to PV. The most important feature that distinguishes solar thermal power technology is its ability to adapt production to demand through thermal inertia inherent in the heat transfer fluid used, the addition of thermal energy storage, and hybridization with conventional fuels, like gas or biomass.

Our solar thermal assets use large parabolic trough mirrors that concentrate the light onto an integral receiver tube. Stainless steel pipes serve as the heat collectors by absorbing high levels of solar radiation while emitting very little infrared radiation. The reflectors and the absorber tubes move in tandem with the sun as it crosses the sky. Synthetic oil is the fluid used to transfer heat from collector pipes to heat exchangers, where water is preheated, evaporated and then superheated into steam. The superheated steam runs a turbine, which drives a generator to produce electricity. After being cooled and condensed, the water returns to the heat exchangers.

Fuel cells

Fuel cells convert fuel, such as natural gas or biogas, into electricity through an electrochemical reaction without burning the fuel. Our fuel cell portfolio utilizes proprietary solid oxide fuel cell technology developed by a third party that also serves as the O&M provider for our entire fuel cell portfolio.

Residential Solar

Our residential solar portfolio consists of PV systems on residential rooftops located primarily in California and Arizona, states that typically have high solar irradiation. Our residential solar customers have entered into lease agreements with us, pursuant to which they make periodic fixed rental payments in exchange for the power generated by the rooftop PV systems.

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Item 3. Legal Proceedings.

See Note 20. Commitments and Contingencies to our consolidated financial statements included in this Annual Report for disclosures concerning our legal proceedings, which disclosures are incorporated herein by reference. 

Item 4. Mine Safety Disclosures.

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock

TerraForm Power’s Common Stock began trading on the Nasdaq under the symbol “TERP” on July 18, 2014. Prior to that, there was no public market for our Common Stock.

Upon the consummation of the Merger, our certificate of incorporation was amended and restated. TerraForm Power’s authorized shares of preferred stock and Common Stock were increased to 100,000,000 shares and 1,200,000,000 shares, respectively. There are no other authorized classes of shares, and we do not have any issued shares of preferred stock.

As of February 28, 2020, there were 13 holders of record of TerraForm Power’s Common Stock, and the closing sale price per share of our Common Stock on the Nasdaq was $18.79. Affiliates of Brookfield held approximately 62% of TerraForm Power’s Common Stock as of that date.

Stock Performance Graph

This performance graph below shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that section, and shall not be deemed to be incorporated by reference into any filing of the Company under the Securities Act or the Exchange Act.

The performance graph below compares TerraForm Power’s cumulative total stockholder return on its Common Stock from July 18, 2014, through December 31, 2019, with the cumulative total return of the Standard & Poor’s 500 Composite Price Index (the “S&P 500”), the Nasdaq Composite Index, as well as our peer group consisting of Atlantica Yield PLC; Clearway Energy, Inc.; NextEra Energy Partners, LP; and Pattern Energy Group Inc.

The performance graph below compares each period assuming that $100 were invested on the initial public offering date in each of the Common Stock of the Company, the stocks in the S&P 500, the Nasdaq Composite Index, our peer group, and that all distributions were reinvested.

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Comparison of Cumulative Total Return

Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities

On October 8, 2019, we completed an underwritten registered public offering of 14,907,573 shares of Common Stock at a price of $16.77 per share (the “Public Offering”), for a total consideration of $250.0 million, not including transaction costs. In connection with the Public Offering, we entered into an underwriting agreement, dated October 3, 2019 with RBC Capital Markets, LLC, as the underwriter.

Concurrent with the Public Offering, on October 8, 2019, we completed a private placement of 2,981,514 shares of Common Stock at a price of $16.77 per share (the “2019 Private Placement”), to BBHC Orion Holdco L.P., an affiliate of Brookfield (the “2019 Private Placement Purchaser”), for a total consideration of $50.0 million, not including transaction costs. No underwriting discounts or commissions were paid with respect to the 2019 Private Placement. In connection with the 2019 Private Placement, we entered into a stock purchase agreement, dated October 8, 2019, with the 2019 Private Placement Purchaser. The Common Stock issued in the 2019 Private Placement were not registered with the SEC, in reliance on Section 4(a)(2) of the Securities Act and the acknowledgment of the 2018 Private Placement Purchaser that it is an “accredited investor” within the meaning of Rule 501(a) of Regulation D of the Securities Act or a “qualified institutional buyer” under Rule 144A of the Securities Act. Following the Public Offering and the 2019 Private Placement, as of December 31, 2019, affiliates of Brookfield held approximately 62% of the Company’s Common Stock.

The proceeds of the Public Offering and 2019 Private Placement were used to repay the amounts due under the Revolver and for general corporate purposes.

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Cash Distributions to Investors

The following table presents cash distributions declared and paid on our Common Stock during the year ended December 31, 2019 and 2018:

	Type	Distributions per Share		Declaration Date	Record Date	Payment Date
2019:
First Quarter	Ordinary	$	0.2014	March 13, 2019	March 24, 2019	March 29, 2019
Second Quarter	Ordinary	0.2014		May 8, 2019	June 3, 2019	June 17, 2019
Third Quarter	Ordinary	0.2014		August 8, 2019	September 3, 2019	September 17, 2019
Fourth Quarter	Ordinary	0.2014		November 6, 2019	December 2, 2019	December 16, 2019
Total		$	0.8056
2018:
First Quarter	Ordinary	$	0.1900	February 6, 2018	February 28, 2018	March 30, 2018
Second Quarter	Ordinary	0.1900		April 30, 2018	June 1, 2018	June 15, 2018
Third Quarter	Ordinary	0.1900		August 13, 2018	September 1, 2018	September 15, 2018
Fourth Quarter	Ordinary	0.1900		November 8, 2018	December 3, 2018	December 17, 2018
Total		$	0.7600

On March 16, 2020, our Board declared a cash distribution with respect to Common Stock of $0.2014 per share. The distribution is payable on March 31, 2020 to stockholders of record as of March 27, 2020. The first quarter of 2020 distribution will be our ninth consecutive quarterly distribution payment under the Brookfield sponsorship.

Share Repurchase Program

On July 25, 2019, our Board authorized the renewal of our share repurchase program through August 4, 2020. Under the share repurchase program, we may repurchase up to 5% of our Common Stock outstanding as of July 25, 2019. The timing and the amount of any repurchases of Common Stock will be determined by us based on our evaluation of market conditions and other factors. Repurchases of Common Stock may be made under a Rule 10b5-1 plan, which would permit Common Stock to be repurchased when we might otherwise be precluded from doing so under insider trading laws, open market purchases, privately-negotiated transactions, block purchases or otherwise in accordance with applicable federal securities laws, including Rule 10b-18 under the Exchange Act. The program may be suspended or discontinued at any time and does not obligate us to purchase any minimum number of stock. Any repurchased Common Stock will be held by us as treasury shares. We expect to fund any repurchases from the available liquidity.

During the fourth quarter of 2019, we repurchased 543,265 shares of Common Stock at a total cost of $8.4 million. The repurchased shares of Common Stock are recorded within Treasury Stock on the Company’s consolidated balance sheets. No shares were repurchased by the Company during the year ended December 31, 2018. The table below summarizes our stock repurchase activity during the fourth quarter of 2019:

	Total Number of Shares Purchased (in thousands)	Average Price Paid per Share (in dollars)		Total Number of Shares Purchased as Part of Publicly Announced Program (in thousands)	Total Number of Shares that May Yet Be Purchased Under the Program (in thousands)
October 1 - October 31, 2019	—	$	—	—	10,458
November 1 - November 30, 2019	293	15.73		293	10,165
December 1 - December 31, 2019	250	14.93		250	9,915
Total	543			543

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Securities Authorized for Issuance under Equity Compensation Plans

For information regarding our equity compensation plans, see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 6. Selected Financial Data.

Our historical selected financial data is presented in the following table. The amounts shown in the table below represent the results of TerraForm Power, which consolidates Terra LLC through its controlling interest. This historical data should be read in conjunction with the consolidated financial statements and the related notes thereto in Item 15. Exhibits, Financial Statements and Schedules and with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Statements of operations data

	Year Ended December 31,
(In thousands, except per share data)	2019		2018		2017		2016		2015
Operating revenues, net	$	941,240	$	766,570	$	610,471	$	654,556	$	469,506
Operating income	113,430		69,979		40,723		88,977		5,514
Net loss	(206,585)		(153,327)		(236,303)		(243,747)		(208,792)
Net loss attributable to non-controlling interests	(57,901)		(165,707)		(76,149)		(120,236)		(129,960)
Net (loss) income attributable to Class A common stockholders	(148,684)		12,380		(160,154)		(123,511)		(78,832)
Basic and diluted (loss) earnings per Class A common share	(0.70)		0.07		(1.61)		(1.40)		$	(1.24)
Distributions declared per Class A common share	0.8056		0.7600		1.9400		—		1.0100

Balance sheet data

	As of December 31,
(In thousands)	2019		2018		2017		2016		2015
Cash and cash equivalents	$	237,480	$	248,524	$	128,087	$	565,333	$	626,595
Restricted cash1	112,020		144,285		96,700		117,504		159,904
Renewable energy facilities, net	7,405,461		6,470,026		4,801,925		4,993,251		5,834,234
Long-term debt and financing lease obligations1	6,235,382		5,761,845		3,598,800		3,950,914		4,562,649
Total assets	10,058,636		9,330,354		6,387,021		7,705,865		8,217,409
Total liabilities	7,427,844		6,561,937		3,964,649		4,810,396		5,101,429
Redeemable non-controlling interests	22,884		33,495		34,660		165,975		175,711
Total stockholders’ equity	2,607,908		2,734,922		2,387,712		2,729,494		2,940,269

———

(1)Including the current portion.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and notes thereto contained herein. The results shown herein are not necessarily indicative of the results to be expected in any future periods. Unless otherwise indicated or otherwise required by the context, references in this section to “we,” “our,” “us,” or the “Company” refer to TerraForm Power, Inc. and its consolidated subsidiaries.

Overview

Our primary business strategy is to acquire, own and operate solar and wind assets in North America and Western Europe. We are the owner and operator of over 4,100 MW diversified portfolio of high-quality solar and wind assets,

underpinned by long-term contracts. Significant diversity across technologies and locations coupled with contracts across a large, diverse group of creditworthy counterparties significantly reduces the impact of resource variability on cash available for distribution and limits our exposure to any individual counterparty. We are sponsored by Brookfield, a leading global alternative asset manager with over $540 billion in assets under management. Affiliates of Brookfield held approximately 62% of our Common Stock as of December 31, 2019.

Our goal is to pay distributions to our stockholders that are sustainable on a long-term basis while retaining within our operations sufficient liquidity for recurring growth capital expenditures and general corporate purposes. We expect to generate this return with a regular distribution, which we intend to grow at 5 to 8% per annum, that is supported by a target payout ratio of 80 to 85% of cash available for distribution and our stable cash flows. We expect to achieve this growth and deliver returns by focusing on the following initiatives:

•Value-Oriented Acquisitions:

With the support of Brookfield, we focus on sourcing off-market transactions at more attractive valuations than auction processes. We believe that multi-faceted transactions such as take-privates and recapitalizations may enable us to acquire high quality assets at attractive relative values.

We have a ROFO to acquire certain renewable power assets in North America and Western Europe owned by Brookfield and its affiliates. The ROFO portfolio currently stands at approximately 3,500 MW. Over time, as Brookfield entities look to sell these assets, we will have the opportunity to make offers for these assets and potentially purchase them if the proposed price (i) meets our investment objectives, and (ii) is the most favorable offered to Brookfield and the applicable Brookfield entities receive all necessary approvals from their independent directors and institutional partners. We also continue to maintain a call right over 500 MW (net) of operating wind power plants that are owned by a warehouse vehicle that was owned and arranged by our previous sponsor, SunEdison, who sold its equity interest in this warehouse vehicle to an unaffiliated third party in 2017.

•Margin Enhancements:

We have sought to enhance our cash flow by optimizing the performance of our existing assets. As our LTSAs for our North American and European wind fleets and North American solar fleet demonstrate, such agreements have the potential to lock in cost savings, provide contractual incentives for achieving our generation targets and increase revenue through deployment of technology.

•Organic Growth:

We continue to develop a robust organic growth pipeline comprised of opportunities to invest in our existing fleet on an accretive basis as well as add-on acquisitions across our scope of operations. We have identified a number of investment opportunities which we believe may be compelling, including asset repowerings, site expansions and adding energy storage to existing sites.

We benefit from Brookfield’s deep operational expertise in owning, operating and developing renewable assets, as well as its significant deal sourcing capabilities and access to capital. Brookfield is a leading global alternative asset manager and has a more than 100-year history of owning and operating assets with a focus on renewable energy, property, infrastructure and private equity. Brookfield has over $50 billion in renewable energy assets representing approximately 19,000 MW of generation capacity in 17 countries. It also employs over 2,800 individuals with extensive operating, development and power marketing capabilities and has a demonstrated ability to deploy capital in a disciplined manner.

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Factors that Significantly Affect our Results of Operations and Business

We expect the following factors will affect our results of operations:

Offtake contracts

Our revenue is primarily a function of the volume of electricity generated and sold by our renewable energy facilities as well as, to a lesser extent, where applicable, the sale of green energy certificates and other environmental attributes related to energy generation. Our current portfolio of renewable energy facilities is generally contracted under long-term PPAs with creditworthy counterparties. As of December 31, 2019, the weighted average remaining life of our PPAs was 13 years. Pricing of the electricity sold under these PPAs is generally fixed for the duration of the contract, although some of our PPAs have price escalators based on an index (such as the consumer price index) or other rates specified in the applicable PPA.

We also generate RECs and SRECs as we produce electricity. RECs and SRECs are accounted for as governmental incentives and are not considered output of the underlying renewable energy facilities. These RECs and SRECs are currently sold pursuant to agreements with third parties and a certain debt holder, and REC and SREC revenue under bundled arrangements is recognized as the underlying electricity is generated if the sale has been contracted with the customer. In some cases, under the terms of certain debt agreements, SRECs generated by the facilities securing the loans are transferred directly to the creditor to repay amounts outstanding under the loans.

Project operations and generation availability

For our Solar and Wind segments, our revenue is a function of the volume of electricity generated and sold by our renewable energy facilities. The volume of electricity generated and sold by our renewable energy facilities during a particular period is impacted by the number of facilities that have achieved commercial operations, as well as both scheduled and unexpected repair and maintenance required to keep our facilities operational. For some of our plants, particularly our wind plants located in Texas, we sell a portion of the power output of the plant on a merchant basis into the wholesale power markets. Any uncontracted energy sales are dependent on the current or day ahead prices in the power markets. Certain of the wholesale markets have experienced volatility and negative pricing.

For our Regulated Solar and Wind segment, revenue is regulated by the Spanish government. In Spain, renewable electricity producers receive a regulated return consisting of two components: (i) the merchant price for the power they produce and (ii) a return on investment payment per MW of installed capacity. For solar plants, there is an additional return on operations payment per MWh produced. This scheme is intended to allow renewable energy producers to recover development costs and obtain a reasonable rate of return on investment. The regulated return rate is set every six years. The first six-year regulatory period started on July 14, 2013 and ended on December 31, 2019. In November 2019, the Spanish government approved a new regulated return rate for the second regulatory period, which began on January 1, 2020 and runs through December 31, 2025. See Item 1. Business -Regulatory Matters - Spain.

The costs we incur to operate, maintain and manage our renewable energy facilities also affect our results of operations. Equipment performance represents the primary factor affecting our operating results because equipment downtime impacts the volume of the electricity that we are able to generate from our renewable energy facilities. The volume of electricity generated and sold by our facilities will also be negatively impacted if any facilities experience higher than normal downtime as a result of equipment failures, electrical grid disruption or curtailment, weather disruptions, or other events beyond our control.

Seasonality and resource variability

The amount of electricity produced and revenues generated by our solar generation facilities is dependent in part on the amount of sunlight, or irradiation, where the assets are located. Shorter daylight hours in the winter months result in less irradiation and the generation produced by these facilities will vary depending on the season. Irradiation can also be variable at a particular location from period to period due to weather or other meteorological patterns, which can affect operating results. As the great majority of our solar power plants are located in the Northern Hemisphere, we expect our current solar portfolio’s power generation to be at its lowest during the first and fourth quarters of each year. Therefore, we expect our first and fourth quarter solar revenues to be lower than in other quarters.

Similarly, the electricity produced and revenues generated by our wind power plants depend heavily on wind conditions, which are variable and difficult to predict. Operating results for renewable energy facilities vary significantly from period to period depending on the wind conditions during the periods in question. As our wind power plants are located in geographies with different profiles, there is some flattening of the seasonal variability associated with each individual wind

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power plant’s generation, and we expect that as the fleet expands the effect of such wind resource variability may be favorably impacted, although we cannot guarantee that we will purchase wind power plants that will achieve such results in part or at all. Historically, our wind production has been greater in the first and fourth quarters, which can partially offset any lower solar revenues in those quarters.

We do not expect seasonality to have a material effect on our ability to pay a regular distribution. We intend to mitigate the effects of any seasonality that we experience by maintaining sufficient liquidity, including cash on hand in order to, among other things, facilitate the payment of distributions to our stockholders.

Cash distribution restrictions

In certain cases, we obtain project-level or other limited or non-recourse financing for our renewable energy facilities which may limit our ability to distribute funds to the Company. These limitations typically require that the project-level cash is used to meet debt obligations and fund operating reserves of the project entities. These financing arrangements also generally limit our ability to distribute funds to the Company if defaults have occurred or would occur with the giving of notice or the lapse of time, or both. Substantially all of those defaults have now been cured or waived. However, if we fail to timely deliver financial statements in the future, or other defaults occur and continue on our non-recourse financing arrangements, we could again be limited in our ability to distribute funds to TerraForm Power in order to pay corporate-level expenses and debt service obligations, as well as to pay distributions to the holders of our Common Stock, and in our ability to comply with corporate-level debt covenants. See Item 1A. Risk Factors. Risks Inherent to an Investment in TerraForm Power, Inc.

Renewable energy facility acquisitions and investments

Our long-term growth strategy is dependent upon our ability to acquire additional renewable power generation assets. This growth is expected to consist of organic growth investments in our existing fleet, add-on acquisitions across our scope of operations and value-oriented opportunistic acquisitions, including through our European Platform.

Renewable power has been one of the fastest growing sources of electricity generation in North America and globally over the past decade. We expect the renewable energy generation segment in particular to continue to offer high growth opportunities driven by:

•the continued reduction in the cost of solar, wind and other renewable energy technologies, which will lead to grid parity in an increasing number of markets;

•distribution charges and the effects of an aging transmission infrastructure, which enable renewable energy generation sources located at a customer’s site, or distributed generation, to be more competitive with, or cheaper than, grid-supplied electricity;

•the replacement of aging and conventional power generation facilities in the face of increasing industry challenges, such as regulatory barriers, increasing costs of and difficulties in obtaining and maintaining applicable permits, and the decommissioning of certain types of conventional power generation facilities, such as coal and nuclear facilities;

•the ability to couple renewable energy generation with other forms of power generation and/or storage, creating a hybrid energy solution capable of providing energy on a 24/7 basis while reducing the average cost of electricity obtained through the system;

•the desire of energy consumers to lock in long-term pricing of a reliable energy source;

•renewable energy generation’s ability to utilize freely available sources of fuel, thus avoiding the risks of price volatility and market disruptions associated with many conventional fuel sources;

•environmental concerns over conventional power generation; and

•government policies that encourage development of renewable power, such as state or provincial renewable portfolio standard programs, which motivate utilities to procure electricity from renewable resources. In addition to renewable energy, we expect natural gas to grow as a source of electricity generation due to its relatively lower cost and lower environmental impact compared to other fossil fuel sources, such as coal and oil.

Our future growth will be dependent in part on Brookfield’s ability to identify and present us with acquisition opportunities, as well as our ability to make successful offers for ROFO assets from Brookfield and its affiliates to the extent the applicable affiliate of Brookfield elects to sell such assets under the terms of the Relationship Agreement. Brookfield’s obligations to TerraForm Power under the Brookfield MSA and Relationship Agreement are subject to a number of exceptions, and Brookfield has no obligation to source acquisition opportunities specifically for us.

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See section Changes with Our Portfolio in Item 1. Business for a summary of the acquisitions that took place during the year ended December 31, 2019.

Access to capital markets

Our ability to acquire additional clean power generation assets and manage our other commitments may be dependent upon our ability to raise or borrow additional funds and access debt and equity capital markets, including the equity capital markets for our Common Stock, the corporate debt markets and the project finance market for project-level debt. We accessed the capital markets several times during the year ended December 31, 2019, including a public offering and a private placement of our Common Stock and other financing transactions related to our Senior Notes, Term Loan, the Revolver and other project-level non-recourse financings, as defined and discussed in Liquidity and Capital Resources below. Limitations on our ability to access the corporate and project finance debt and equity capital markets in the future on terms that are accretive to our existing cash flows would be expected to negatively affect our results of operations, business and future growth.

Foreign exchange

Our operating results are reported in United States dollars. A significant portion of our revenues and expenses are generated in foreign currencies, primarily the Euro, and the Canadian dollar. This mix of currencies may continue to change in the future if we elect to alter the mix of our portfolio within our existing markets or elect to expand into new markets. In addition, our investments (including intercompany loans) in renewable energy facilities in certain foreign countries are exposed to foreign currency fluctuations. As a result, we expect our revenues and expenses will be exposed to foreign exchange fluctuations in local currencies where our renewable energy facilities are located. To the extent we do not hedge these exposures, fluctuations in foreign exchange rates could negatively impact our profitability and financial position.

Interest rates

In July 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. Currently, it is not possible to predict the exact transitional arrangements for calculating applicable reference rates that may be made in the U.K., the U.S., the Eurozone or elsewhere given that a number of outcomes are possible, including the cessation of the publication of one or more reference rates. Certain of our loan documents contain provisions that contemplate alternative calculations of the base rate applicable to our LIBOR-indexed debt to the extent LIBOR is not available, which alternative calculations we do not anticipate will be materially different from what would have been calculated under LIBOR. Additionally, no mandatory prepayment or redemption provisions would be triggered under our loan documents in the event that the LIBOR rate is not available. It is possible, however, that any new reference rate that applies to our LIBOR-indexed debt could be different than any new reference rate that applies to our LIBOR-indexed derivative instruments. We anticipate managing this difference and any resulting increased variable-rate exposure through modifications to our debt and/or derivative instruments; however, future market conditions may not allow immediate implementation of desired modifications and/or we may incur significant associated costs.

Key Metrics

Factors Affecting the Comparability of our Financial Results

The comparability of our consolidated results of operations among the periods presented is impacted by the acquisitions we make. Acquisitions completed during one period impact the comparability to a prior period in which we did not own the acquired businesses or assets. Accordingly, our historical consolidated results of operations may not be comparable or indicative of future results.

The below represent the key acquisitions that affect the comparability of our financial results:

The Saeta Acquisition

As discussed in Note 3. Acquisitions and Divestitures to our consolidated financial statements, we acquired an over 95% of the outstanding equity interests in Saeta Yield S.A (“Saeta” or “European Platform”, as the context may require), a Spanish renewable power company with then 1,000 MW of wind and solar facilities (approximately 250 MW of solar and 778 MW of wind) located primarily in Spain, on June 12, 2018 (“the Saeta Acquisition Date”). We completed a statutory squeeze-out procedure under Spanish law to procure the remaining outstanding equity interests in Saeta on July 2, 2018. Our consolidated results for the year ended December 31, 2019, include the results of Saeta for the full period, whereas the

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comparable consolidated results for the year ended December 31, 2018 include the results effective from the Saeta Acquisition Date.

The WGL Acquisition

As discussed in Note 3. Acquisitions and Divestitures to our consolidated financial statements, we acquired an approximately 320 MW distributed generation portfolio of renewable energy facilities in the United States from subsidiaries of AltaGas (the “WGL Acquisition”) on September 26, 2019. Our consolidated results for the year ended December 31, 2019 include the results relating to the WGL Acquisition beginning on the acquisition date on September 26, 2019.

Operating Metrics

Nameplate capacity

We measure the electricity-generating production capacity of our renewable energy facilities in nameplate capacity. Rated capacity is the expected maximum output a power generation system can produce without exceeding its design limits. We express nameplate capacity in (1) direct current (“DC”), for all facilities within our Solar reportable segment, and (2) alternating current (“AC”) for all facilities within our Wind and Regulated Solar and Wind reportable segments. The size of our renewable energy facilities varies significantly among the assets comprising our portfolio. We believe the combined nameplate capacity of our portfolio is indicative of our overall production capacity and period to period comparisons of our nameplate capacity are indicative of the growth rate of our business. Our renewable energy facilities had an aggregate nameplate capacity of 4,122.5 MW and 3,748 MW as of December 31, 2019 and 2018, respectively.

Gigawatt hours sold

Gigawatt hours (“GWh”) sold refers to the actual volume of electricity sold by our renewable energy facilities during a particular period. We track GWh sold as an indicator of our ability to realize cash flows from the generation of electricity at our renewable energy facilities. Our GWh sold for renewable energy facilities for the years ended December 31, 2019, and 2018 were as follows:

	Year Ended December 31,
(In GWh)	2019	2018
Solar segment	1,873	1,819
Wind segment	5,591	5,457
Regulated Solar and Wind segment1	1,778	812
Total	9,242	8,088

———

(1)Our Regulated Solar and Wind segment was added upon the acquisition of a controlling interest in Saeta that was completed on June 12, 2018.

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Consolidated Results of Operations

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

The amounts shown below represent the results of TerraForm Power’s wholly-owned and partially-owned subsidiaries in which we have a controlling interest, with all significant intercompany accounts and transactions eliminated. The discussion and analysis of our results of operations below includes a comparison of the year ended December 31, 2019 to the year ended December 31, 2018. A similar discussion and analysis of our results of operations including a comparison of the year ended December 31, 2018 to the year ended December 31, 2017 can be found in Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operation”, in our annual report on Form 10-K for the year ended December 31, 2018.

	Year Ended December 31,
(In thousands)	2019		2018
Operating revenues, net	$	941,240	$	766,570
Operating costs and expenses:
Cost of operations	279,896		220,907
General and administrative expenses	81,063		87,722
General and administrative expenses - affiliate	28,070		16,239
Acquisition costs	3,751		7,721
Acquisition costs - affiliate	920		6,925
Impairment of renewable energy facilities	—		15,240
Depreciation, accretion and amortization expense	434,110		341,837
Total operating costs and expenses	827,810		696,591
Operating income	113,430		69,979
Other expenses (income):
Interest expense, net	298,142		249,211
Loss on modification and extinguishment of debt, net	26,953		1,480
Gain on sale of renewable energy facilities	(2,252)		—
Gain on foreign currency exchange, net	(12,726)		(10,993)
Other income, net	(2,000)		(4,102)
Total other expenses, net	308,117		235,596
Loss before income tax expense (benefit)	(194,687)		(165,617)
Income tax expense (benefit)	11,898		(12,290)
Net loss	(206,585)		(153,327)
Less: Net loss attributable to non-controlling interests	(57,901)		(165,707)
Net (loss) income attributable to Class A common stockholders	$	(148,684)	$	12,380

———

(1)Including redeemable non-controlling interests.

The following table reflects summarized financial information for our reportable segments for the years ended December 31, 2019, 2018:

	Year Ended December 31, 2019
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	—	$	941,240
Depreciation, accretion and amortization expense	118,564		175,842		138,213		1,491		434,110
Other operating costs and expenses	66,334		142,031		90,516		94,819		393,700
Operating income (loss)	131,535		(31,734)		109,939		(96,310)		113,430
Interest expense, net	68,441		58,105		54,727		116,869		298,142
Other non-operating (income) expenses, net	(7,893)		(455)		3,994		14,329		9,975
Income tax expense (benefit)	2,309		193		1,326		8,070		11,898
Net income (loss)	$	68,678	$	(89,577)	$	49,892	$	(235,578)	$	(206,585)

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	Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	298,966	$	280,949	$	186,655	$	—	$	766,570
Depreciation, accretion and amortization expense	109,809		151,472		79,026		1,530		341,837
Impairment of renewable energy facilities	15,240		—		—		—		15,240
Other operating costs and expenses	74,778		123,203		46,289		95,244		339,514
Operating income (loss)	99,139		6,274		61,340		(96,774)		69,979
Interest expense, net	63,571		50,712		15,510		119,418		249,211
Other non-operating income, net	(4,248)		(108)		(2,261)		(6,998)		(13,615)
Income tax (benefit) expense	(20,346)		79		10,558		(2,581)		(12,290)
Net income (loss)	$	60,162	$	(44,409)	$	37,533	$	(206,613)	$	(153,327)

Operating Revenues, net

Operating revenues, net and GWh sold for the years ended December 31, 2019 and 2018 were as follows:

	Year Ended December 31,
(In thousands, except GWh sold)	2019		2018		Change
Energy:
Solar	$	237,156	$	228,433	$	8,723
Wind	276,725		264,585		12,140
Regulated Solar and Wind	302,944		166,984		135,960
Incentives, including affiliates:
Solar	79,277		70,533		8,744
Wind	9,414		16,364		(6,950)
Regulated Solar and Wind	35,724		19,671		16,053
Total operating revenues, net	$	941,240	$	766,570	$	174,670
GWh sold:
Solar	1,873		1,819		54
Wind	5,591		5,457		134
Regulated Solar and Wind	1,778		812		966
Total GWh sold	9,242		8,088		1,154
	December 31,
Nameplate capacity (MW):	2019		2018		Change
Solar	1,421		1,092		329
Wind	1,864		1,864		—
Regulated Solar and Wind	837		792		45
Total nameplate capacity	4,122		3,748		374

Total energy revenue increased by $156.8 million for the year ended December 31, 2019, compared to 2018 due to increases at all segments. Energy revenue from our Solar segment increased by $8.7 million during the year ended December 31, 2019, compared to 2018, primarily due to $10.3 million contribution in revenue from the WGL Acquisition that was partially offset by $1.7 million decrease at other facilities in North America. Energy revenue for our Wind segment increased by $12.1 million during the year ended December 31, 2019, compared to 2018, primarily driven by a $33.8 million increase from Saeta’s operations in Portugal and Uruguay that were acquired on June 12, 2018, and are reflected in the results of the

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comparable period only effective from the Saeta Acquisition Date. The increase in energy revenue at our Wind segment was partially offset by $21.7 million decrease at our North American operations. The decrease at our North American operations were primarily attributable to (i) $9.5 million increase in unrealized losses on commodity derivative contracts not designated as hedging instruments, (ii) $7.0 million decrease in availability due to our blade inspection program and the transition to a new O&M provider, (iii) $6.6 million decrease driven by contract expiration and decrease in pricing in the North East, and (v) $4.0 million reduction due to lower basis pricing in Texas as a result of continued challenged market conditions. These decreases at our North American wind operation were partially offset by $5.2 million increase in revenue due to improved resource. Energy revenue at our Regulated Solar and Wind segment, representing the entire operations of our European Platform in Spain, increased by $136.0 million during the year ended December 31, 2019, compared to 2018, which reflects the results effective from the Saeta Acquisition Date.

Incentive revenue for our Solar segment increased by $8.7 million during the year ended December 31, 2019, compared to 2018, primarily due to (i) $4.7 million increase in revenue from the WGL Acquisition, (ii) $2.0 million increase from other distributed generation facilities in Massachusetts that were acquired during in June 2019 and (iii) other increases due to the timing of contracting incentive contracts in the United States. Incentive revenue for our Wind segment decreased by $7.0 million, primarily due to the expiration of favorable contracts. Incentive revenue at our Regulated Solar and Wind segment, representing earnings for each MWh produced by our solar facilities in Spain to recover deemed operating costs that are in excess of market revenue forecasted by the CNMC, increased by $16.1 million during the year ended December 31, 2019, compared to 2018, which reflects the results effective from the Saeta Acquisition Date.

Cost of Operations

Cost of operations for the years ended December 31, 2019 and 2018 was as follows:

	Year Ended December 31,
(In thousands)	2019		2018		Change
Solar	$	63,176	$	64,343	$	(1,167)
Wind	134,639		116,017		18,622
Regulated Solar and Wind	82,081		40,547		41,534
Total cost of operations	$	279,896	$	220,907	$	58,989

Total cost of operations increased by $59.0 million for the year ended December 31, 2019, compared to 2018 due to $18.6 million increase at our Wind segment, and $41.5 million increase at our Regulated Solar and Wind segment. These increases were partially offset by $1.2 million decrease at our Solar segment. Cost of operations at our Solar segment decreased by $1.2 million for the year ended December 31, 2019, compared to 2018 primarily due to the recovery of $4.2 million note receivable related to an interconnection agreement with a public utility company that filed for protection under Chapter 11 of the U.S. bankruptcy code in California. This reduction in costs was partially offset by $3.0 million increases at our North American facilities. Cost of operations for our Wind segment increased by $18.6 million primarily due to (i) $5.8 million increases in costs related to Saeta’s projects in Portugal and Uruguay that were acquired during the second half of 2018; (ii) $3.1 million cost for studies and analyses of potential repowering in in the North East, (iii) $10.3 million additional write-offs of renewable energy facilities in the North East, and (iv) $7.2 million increase in repairs and maintenance costs for our North American Wind fleet primarily related from our blades inspection program. The increase in the cost operations for our Wind segment were partially offset by a $8.0 million reduction in variable O&M costs in North America. Cost of operations for our Regulated Solar and Wind segment, representing the entire operations of our European Platform in Spain, increased by $41.5 million during the year ended December 31, 2019, compared to 2018, which reflects the results effective from the Saeta Acquisition Date.

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General and Administrative Expenses

General and administrative expenses for the years ended December 31, 2019 and 2018 were as follows:

	Year Ended December 31,
(In thousands)	2019		2018		Change
Solar	$	3,158	$	10,435	$	(7,277)
Wind	7,392		7,186		206
Regulated Solar and Wind	7,515		5,742		1,773
Corporate	62,998		64,359		(1,361)
Total general and administrative expenses	$	81,063	$	87,722	$	(6,659)

Total general and administrative expenses decreased by $6.7 million for the year ended December 31, 2019, compared to 2018, primarily due to a $7.3 million decrease at our Solar segment. The decrease in general and administrative expenses at our Solar segment was primarily attributable to a $3.5 million decrease in sales and use taxes in the United States, and $3.6 million decrease in expenses related to reorganization of certain entities in the United States in 2018.

General and Administrative Expenses - Affiliate

General and administrative expenses - affiliate for the years ended December 31, 2019 and 2018 were as follows:

	Year Ended December 31,
(In thousands)	2019		2018		Change
Corporate	$	28,070	$	16,239	$	11,831

General and administrative expenses - affiliate were $28.1 million for the year ended December 31, 2019, which consisted of a $26.8 million base management fee pursuant to the Brookfield MSA and $1.3 million of rent and other related expenses primarily associated with our corporate headquarters in New York. The $11.8 million increase during the year ended December 31, 2019, compared to 2018, was primarily due to a $12.2 million increase in the base management fee primarily driven by the increase in our market capitalization. See Note 21. Related Parties to our consolidated financial statements for additional details.

Acquisition Costs

Acquisition costs paid to third parties for the years ended December 31, 2019 and 2018 were as follows:

	Year Ended December 31,
(In thousands)	2019		2018		Change
Corporate	$	3,751	$	7,721	$	(3,970)

Acquisition costs - affiliate for the years ended December 31, 2019 and 2018 were as follows:

	Year Ended December 31,
(In thousands)	2019		2018		Change
Regulated Solar and Wind	$	920	$	—	$	920
Corporate	—		6,925		(6,925)
Total acquisition costs - affiliate	$	920	$	6,925	$	(6,005)

Total acquisition costs, including those related to affiliates, were $4.7 million for the year ended December 31, 2019, and consisted primarily of professional fees for legal, valuation and accounting services incurred in relation to our acquisition of the WGL Acquisition and other acquisitions in Spain. Costs related to affiliates included in this balance were $0.9 million representing reimbursements to affiliates of Brookfield for fees and expenses incurred on behalf of us. Total acquisition costs for the year ended December 31, 2018 were $14.6 million, and consisted, primarily of investment banker advisory fees

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and professional fees for legal and accounting services. Costs related to affiliates included in this balance were $6.9 million representing reimbursements to affiliates of Brookfield for fees and expenses incurred on behalf of us. These costs are reflected as acquisition costs and acquisition costs - affiliate. See Note 21. Related Parties to our consolidated financial statements.

Impairment of Renewable Energy Facilities

We did not record any impairment losses for the year ended December 31, 2019. For the year ended December 31, 2018, we recognized an impairment loss of $15.2 million related to a certain distributed generation portfolio. We had a renewable energy certificate sales agreement with a customer expiring December 31, 2021, and on March 31, 2018, this customer filed for protection under Chapter 11 of the U.S. Bankruptcy Code. The potential replacement of this contract resulted in a significant decrease to our expected operating revenues. Our analysis indicated that the bankruptcy filing was a triggering event to perform an impairment evaluation. We recorded the difference between the carrying amount of non-current assets and the estimated fair value within Impairment of renewable energy facilities in the consolidated financial statements. See Note 6. Renewable Energy Facilities to our consolidated financial statements for additional details.

Depreciation, Accretion and Amortization Expense

Depreciation, accretion and amortization expense increased by $92.3 million during the year ended December 31, 2019, compared to 2018, primarily as a result of incremental depreciation, accretion and amortization associated with acquired renewable energy assets from the Saeta acquisition and the WGL Acquisition, as well as capital additions placed in service in 2019.

Interest Expense, Net

Interest expense, net for the years ended December 31, 2019 and 2018 was as follows:

	Year Ended December 31,
(In thousands)	2019		2018		Change
Corporate-level	$	116,869	$	119,418	$	(2,549)
Non-recourse:
Solar	68,441		63,571		4,870
Wind	58,105		50,712		7,393
Regulated Solar and Wind	54,727		15,510		39,217
Total interest expense, net	$	298,142	$	249,211	$	48,931

Interest expense, net for the year ended December 31, 2019, increased by $48.9 million compared to 2018, due to (i) $4.9 million increase at our solar segment, (ii) $7.4 million at our wind segment, and (iii) $39.2 million increase at our Regulated Solar and Wind segments. These increases were partially offset by $2.5 million decrease at our corporate segment. The increases at our Solar and Wind segments were primarily related to new non-recourse borrowings obtained during 2019. The increase at our Wind and Regulated Solar and Wind segments, primarily at our European Platform and our wind plants in Portugal and Uruguay, compared to the same period in 2018, which reflects the results only effective from the Saeta Acquisition Date. The decrease at our Corporate segment is primarily related to the payment of the outstanding balances under the Revolver and the repayment of our Term Loan. See Note 10. Long-term Debt to our consolidated financial statements for additional details.

Loss on Modification and Extinguishment of Debt, net

Loss on modification and extinguishment of debt, net includes prepayment penalties, the write-off of unamortized deferred financing costs and debt premiums or discounts, costs incurred in a debt modification that are not capitalized as deferred financing costs, other costs incurred in relation to debt extinguishment, and any gain from the redemption of debt below its carrying amount. We incurred a net loss on modification and extinguishment of debt of $27.0 million for the year ended December 31, 2019, compared to $1.5 million in 2018. The loss for the year ended December 31, 2019 comprised $26.8 million loss on the extinguishment of corporate debt and $0.2 million net loss on the modification and extinguishment of certain non-recourse project debt and financing lease obligations. The loss for the year ended December 31, 2018 represented the deferred financing costs written off and other charges related to the repricing of our senior secured term loan that took place in May of 2018. See Note 10. Long-term Debt to our consolidated financial statements for additional details.

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Gain on Sale of Renewable Energy Facilities

On December 20, 2019, we sold six distributed generation facilities in the United States, with a combined nameplate capacity of 6.0 MW, for a net consideration of $9.5 million. We recognized a net gain of $2.3 million representing the difference between the net proceeds from the sale and the net carrying amount of assets sold and liabilities extinguished, which was recorded in the consolidated statement of operations for the year ended December 31, 2019 within the Gain on sale of renewable energy facilities.

Gain on Foreign Currency Exchange, net

We recognized a net gain on foreign currency exchange of $12.7 million for the year ended December 31, 2019, primarily due to a total $27.2 million net realized and unrealized gain on foreign currency derivative contracts that were partially offset by a loss of $14.5 million on the remeasurement of intercompany loans, which primarily denominated in Euro. We recognized a net gain on foreign currency exchange of $11.0 million for the year ended December 31, 2018, primarily due to a total $34.7 million net realized and unrealized gain on foreign currency derivative contracts that were partially offset by a loss of $24.1 million on the remeasurement of intercompany loans, which were primarily denominated in Euro.

Other Income, net

We recognized $2.0 million of other income, net for the year ended December 31, 2019 compared to $4.1 million for the year ended December 31, 2018. The balance primarily consisted of reimbursements and recoveries received for damages and other losses.

Income Tax Expense

We recognized income tax expense of $11.9 million for the year ended December 31, 2019, compared to $12.3 million benefit for 2018. A valuation allowance is recorded against certain deferred tax assets in the U.S., Chile and certain other jurisdictions, primarily due to the history of losses in those jurisdictions. The income tax expense recognized for the year ended December 31, 2019, comprised $9.4 million expense attributable to our North American operations, primarily due to adjustments to the deferred taxes valuation allowance, and $2.5 million attributable to our European operations. The $12.3 million income tax benefit for year ended December 31, 2018, comprised $20.1 million benefit due to the reorganization of certain entities in the United States which resulted in a decrease in the valuation allowance for deferred tax assets in the U.S. This income tax benefit was partially offset by $7.8 million deferred tax expense on profitable jurisdictions, primarily in Spain. For the years ended December 31, 2019 and 2018, the overall effective tax rates were different than the statutory rates in the United States of 21% primarily due to the recording of valuation allowances on certain income tax benefits, allocated to non-controlling interests, and the effect of foreign and state taxes. See Note 11. Income Taxes to our consolidated financial statements for additional details.

Net Loss Attributable to Non-Controlling Interests

Net loss attributable to non-controlling interests, including redeemable non-controlling interests, was $57.9 million for the year ended December 31, 2019, and represents the portions of the profits and losses in consolidated entities that are not owned by us. Net loss attributable to non-controlling interests for the year ended December 31, 2018, was $165.7 million. The balance for the prior period included $151.2 million loss allocated to non-controlling interests related to a reduction in the tax rate used in our hypothetical liquidation valuation at book value methodology as a result of the Tax Cuts and Jobs Act, which enacted major changes to the U.S. tax code effective the year 2018. See Note 18. Non-Controlling Interests to our consolidated financial statements for additional details.

Liquidity and Capital Resources

Capitalization

A key element to our financing strategy is to raise the majority of our debt in the form of project specific non-recourse borrowings at our subsidiaries with investment grade metrics. Going forward, we intend to primarily finance acquisitions or growth capital expenditures using long-term non-recourse debt that fully amortizes within the project’s contracted life at investment grade metrics, as well as retained cash flows from operations, issuance of equity securities through public markets and opportunistic sales of projects, portfolios of projects, or of non-controlling interests in projects or portfolios of projects.

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Public Offering and Concurrent Private Placement of Common Stock

On October 8, 2019, we completed an underwritten registered public offering of 14,907,573 shares of our Common Stock for gross proceeds of approximately $250.0 million. Concurrently with the public offering, on October 8, 2019, an affiliate of Brookfield purchased 2,981,514 shares in a private placement at the same price per share paid in the public offering representing gross proceeds of $50.0 million. The proceeds of these offerings were used to pay down the amounts due under the Revolver and for general corporate purposes. See Note 16. Stockholders’ Equity to our consolidated financial statements for additional details.

The following table summarizes the total capitalization and debt to capitalization percentage as of December 31, 2019 and 2018:

	As of December 31,
(In thousands)	2019			2018
Revolving Credit Facilities1	$	—		$	377,000
Senior Notes2, 3	1,900,000			1,500,000
Term Loan3	—			346,500
Non-recourse long-term debt, including current portion4	4,388,469			3,573,436
Long-term indebtedness, including current portion5	6,288,469			5,796,936
Total stockholders’ equity and redeemable non-controlling interests	2,630,792			2,768,417
Total capitalization	$	8,919,261		$	8,565,353
Debt to total capitalization	71		%	68		%

———

(1)Represents the drawn amounts under our Revolver and does not include $115.5 million of outstanding project-level letters of credit.

(2)Represents our Senior Notes due 2023, Senior Notes due 2028 and Senior Notes due 2030.

(3)On October 16, 2019, Terra Operating, LLC issued $700.0 million of 4.75% senior notes due on January 15, 2030 at an offering price of 100% of the principal amount. The proceeds from these notes were used to redeem, in full, our existing Senior Notes due 2025 and Term Loan. See the Financing Activities section below for discussion regarding 2018 and 2019 activity.

(4)Represents asset-specific, non-recourse borrowings and financing lease obligations secured against the assets of certain project companies.

(5)Represents the total principal due for long-term debt and financing lease obligations, including the current portion, which excludes $53.1 million and $35.1 million of net unamortized debt premiums, discounts and deferred financing costs as of December 31, 2019 and 2018, respectively.

Liquidity Position

We operate with sufficient liquidity to enable us to fund cash distributions, growth initiatives, capital expenditures and withstand sudden adverse changes in economic circumstances or short-term fluctuations in resource. Principal sources of funding are cash flows from operations, revolving credit facilities (including our Revolver and Sponsor Line as discussed and defined below), unused debt capacity at our projects, non-core asset sales and proceeds from the issuance of debt or equity securities through public markets.

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The following table summarizes corporate liquidity and available capital as of December 31, 2019 and 2018:

	As of December 31,
(In thousands)	2019		2018
Unrestricted corporate cash	$	54,419	$	52,506
Project-level distributable cash	44,556		18,414
Cash available to corporate	98,975		70,920
Credit facilities:
Committed revolving credit facility1	800,000		600,000
Drawn portion of revolving credit facilities	—		(377,000)
Revolving line of credit commitments	(115,549)		(99,487)
Undrawn portion of Sponsor Line2	500,000		500,000
Available portion of credit facilities	1,184,451		623,513
Corporate liquidity	1,283,426		694,433
Other project-level unrestricted cash	138,505		177,604
Project-level restricted cash	112,020		144,285
Available capital	$	1,533,951	$	1,016,322

———

(1)On October 8, 2019, we entered into an amendment agreement to (i) increase aggregate lending commitments limit from $600.0 million to $800.0 million, (ii) extend the maturity date by one year to October 5, 2024 and (iii) provide for the ability to further increase the lending commitments by an additional $150.0 million.

(2)Represents a $500.0 million secured revolving credit facility we entered into pursuant to a credit agreement (the “Sponsor Line”) with Brookfield and one of its affiliates that may only be used to fund all or a portion of certain funded acquisitions or growth capital expenditures.

Financing Activities

Corporate-level Long-term Debt

Senior Notes

On January 28, 2015, we issued $800.0 million of 5.88% senior notes due 2023 at an offering price of 99.214% of the principal amount. On June 11, 2015, issued an additional $150.0 million of 5.875% senior notes due 2023 (collectively, with the $800.0 million initially issued, the “Old Senior Notes due 2023”). The offering price of the additional $150.0 million of notes was 101.5% of the principal amount. On July 17, 2015, we issued $300.0 million of 6.125% senior notes due 2025 at an offering price of 100% of the principal amount (the “Senior Notes due 2025”).

On December 12, 2017, we issued $500.0 million of 4.25% senior notes due 2023 at an offering price of 100% of the principal amount (the “Senior Notes due 2023”) and $700.00 million of 5.00% senior notes due 2028 at an offering price of 100% of the principal amount (the “Senior Notes due 2028”). We used the net proceeds of the offering of the Senior Notes due 2023 and Senior Notes due 2028 to redeem, in full, our Old Senior Notes due 2023, of which $950.0 million remained outstanding, at a redemption price that included a prepayment penalty of $50.7 million, plus accrued and unpaid interest, and to repay $150.0 million of revolving loans outstanding under the Revolver, as described below.

        On October 16, 2019, we issued $700.0 million aggregate principal amount of 4.75% senior notes due on January 15, 2030, at an offering price of 100% of the principal amount (the “Senior Notes due 2030” and, together with the Senior Notes due 2023 and the Senior Notes due 2028, the “Senior Notes”), in an unregistered offering pursuant to Rule 144A under the Securities Act. We used the net proceeds from the offering of the Senior Notes due 2030 to (i) redeem, in full, our Senior Notes due 2025, of which $300.0 million remained outstanding, at a redemption price that included a prepayment penalty of $18.3 million, plus accrued interest, (ii) redeem, in full, our Term Loan (as defined below), of which $343.9 million remained outstanding plus accrued interest, (iii) redeem, in full, derivative liabilities related to interest rate swaps with hedge counterparties of which $8.8 million remained outstanding, and (iii) pay for the fees and expenses related to the issuance.

The Senior Notes are senior obligations of Terra Operating LLC and are guaranteed by Terra LLC and each of Terra Operating LLC’s subsidiaries that guarantee the Revolver (as defined below) or certain other material indebtedness of Terra

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Operating LLC or Terra LLC. Each series of the Senior Notes rank equally in right of payment with all existing and future senior indebtedness of Terra Operating LLC, including the Revolver, senior in right of payment to any future subordinated indebtedness of Terra Operating LLC, and effectively subordinated to all borrowings under the Revolver, which are secured by substantially all of the assets of Terra Operating LLC and the guarantors of the Senior Notes.

At its option, Terra Operating LLC may redeem some or all of each series of the Senior Notes at any time or from time to time before their maturity. If Terra Operating LLC elects to redeem the Senior Notes due 2023 prior to October 31, 2022, the Senior Notes due 2028 before July 31, 2027, or the Senior Notes due 2030 before January 15, 2028, Terra Operating LLC would be required to pay a prepayment penalty as set forth in the applicable indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2023, the Senior Notes due 2028, or the Senior Notes due 2030 on or after these respective dates, Terra Operating LLC would be required to pay a redemption price equal to 100% of the aggregate principal amount of the Senior Notes redeemed plus accrued and unpaid interest thereon. If certain change of control triggering events occur in the future, Terra Operating LLC must offer to repurchase all of each series of the Senior Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the repurchase date.

Term Loan

On November 8, 2017, we entered into a 5-year $350.0 million senior secured term loan (the “Term Loan”) and used the net proceeds to repay outstanding borrowings under a non-recourse project-level term debt and $50.0 million of revolving loans outstanding under the Revolver. The Term Loan originally bore interest at a rate per annum equal to, at our option, either (i) a base rate plus a margin of 1.75% or (ii) a reserve adjusted Eurodollar rate plus a margin of 2.75%, and is secured and guaranteed equally and ratably with the Revolver. The Term Loan provided for voluntary prepayments, in whole or in part, subject to notice periods. There were no prepayment penalties or premiums other than customary breakage costs after the six-month anniversary of the closing date. Within the first six months following the closing date, a prepayment premium of 1.00% would apply to any principal amounts that were prepaid. On May 11, 2018, we entered into an amendment to the Term Loan, whereby the interest rate was reduced by 0.75% per annum. On March 8, 2019, we entered into interest rate swap agreements with counterparties to hedge the cash flows associated with the interest payments on the entire principal of the Term Loan, paying an average fixed rate of 2.54%. In return, the counterparties agreed to pay the variable interest payments due to the lenders until maturity. On October 17, 2019, Terra Operating LLC repaid, in full, the amounts outstanding, including the accrued interest, under the Term Loan using the proceeds of the offering of the Senior Notes due 2030.

Revolver

On October 17, 2017, we entered into a senior secured revolving credit facility (the “Revolver”) in an initial amount of $450.0 million, available for revolving loans and letters of credit, and maturing in October 2021. All outstanding amounts originally bore interest at a rate per annum equal to, at our option, either (i) a base rate plus a margin ranging between 2.00% to 2.00% or (ii) a reserve adjusted Eurodollar rate plus a margin ranging between 2.25% to 3.0%. In addition to paying interest on outstanding principal under the Revolver, Terra Operating LLC is required to pay a standby fee in respect of the unutilized commitments thereunder, payable quarterly in arrears. This standby fee ranges between 0.375% and 0.50% per annum. The Revolver provides for voluntary prepayments, in whole or in part, subject to notice periods. There are no prepayment penalties or premiums other than customary breakage costs. On February 6, 2018, we entered into an amendment to increase the facility limit to $600.0 million. On October 5, 2018, Terra Operating LLC entered into an amendment to (i) reduce the interest rate by 0.75% per annum, and (ii) extend the maturity date of the Revolver to October 2023. On October 8, 2019, Terra Operating LLC entered into an amendment to the Revolver agreement (the “Upsize Amendment”) whereby (i) the aggregate size of the commitments to make revolving loans (‘‘Revolving Loans’’) under the Revolver was increased by $200.0 million to $800.00 million, shared ratably among the existing lenders under the Revolver and three new incoming lenders as of October 8, 2019, (ii) the aggregate size of the letter of credit facility under the Revolver was increased by $50.0 million to $300.0 million and (iii) the accordion feature of the Revolver, which allows for further increases to the commitments to make Revolving Loans, was set at $150.0 million. Additionally, the Upsize Amendment extended the maturity date of the Revolver by one year to October 5, 2024.

The Revolver currently bears interest at a rate equal to, our option, either (i) LIBOR plus an applicable margin ranging from 1.50% to 2.25% per annum, or (ii) a base rate plus an applicable margin ranging from 0.50% to 1.25% per annum. We did not incur additional debt or receive any proceeds in connection with the October 5, 2018 amendment.

Under the Revolver, each of Terra Operating LLC’s existing and subsequently acquired or organized domestic restricted subsidiaries (excluding non-recourse subsidiaries) and Terra LLC are or will become guarantors. The Revolver, each guarantee and any interest rate, currency hedging or hedging of REC obligations of Terra Operating LLC or any guarantor owed to the administrative agent, any arranger or any lender under the Revolver is secured by first priority security interests in

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(i) all of Terra Operating LLC’s, each guarantor’s and certain unencumbered non-recourse subsidiaries’ assets, (ii) 100% of the capital stock of each of Terra Operating LLC and its domestic restricted subsidiaries and 65% of the capital stock of Terra Operating LLC’s foreign restricted subsidiaries and (iii) all intercompany debt. The Revolver is secured equally and ratably with the Term Loan.

Sponsor Line Agreement

On October 16, 2017, TerraForm Power entered into a credit agreement (the “Sponsor Line”) with Brookfield and one of its affiliates. The Sponsor Line establishes a $500.0 million secured revolving credit facility and provides for the lenders to commit to making LIBOR loans to us during a period not to exceed three years from the effective date of the Sponsor Line (subject to acceleration for certain specified events). We may only use the revolving Sponsor Line credit facility to fund all or a portion of certain funded acquisitions or growth capital expenditures. The Sponsor Line terminates, and all obligations thereunder become payable, no later than October 16, 2022.

Borrowings under the Sponsor Line bear interest at a rate per annum equal to a LIBOR rate determined by reference to the costs of funds for U.S. dollar deposits for the interest period relevant to such borrowing adjusted for certain additional costs, in each case plus 3.0% per annum. In addition to paying interest on outstanding principal under the Sponsor Line, we are required to pay a standby fee of 0.50% per annum in respect of the unutilized commitments thereunder, payable quarterly in arrears. We are permitted to voluntarily reduce the unutilized portion of the commitment amount and repay outstanding loans under the Sponsor Line at any time without premium or penalty, other than customary “breakage” costs. TerraForm Power’s obligations under the Sponsor Line are secured by first-priority security interests in substantially all assets of TerraForm Power, including 100% of the capital stock of Terra LLC, in each case subject to certain exclusions set forth in the credit documentation governing the Sponsor Line. Under certain circumstances, we may be required to prepay amounts outstanding under the Sponsor Line.

During the year ended December 31, 2018, we made two draws on the Sponsor Line totaling $86.0 million. We used the proceeds to fund the acquisition of Saeta and were repaid in full as of December 31, 2018. We did not make any draws on the Sponsor Line during the years ended December 31, 2019, and 2017. See Note 21. Related Parties to our consolidated financial statements for details.

Non-recourse Project Finance

United States Project Financings

On May 29, 2019, one of our subsidiaries entered into a new non-recourse debt financing agreement of $104.1 million senior secured term loan facility, and secured by approximately 137.7 MW of distributed generation solar power facilities located in the U.S. We used the net proceeds of this debt to repay a portion of the Revolver and for general corporate purposes. The debt bears interest at a rate per annum equal to three month LIBOR plus an applicable margin of 200 basis points that increases by 12.5 basis points every four years until maturity. We entered into interest rate swap agreements with counterparties to hedge the interest payments associated with the debt, paying a fixed rate of 2.3%. In return, the counterparties agreed to pay the variable interest payments to the lenders.

On August 30, 2019, one of our subsidiaries entered into a new non-recourse debt financing agreement issuing $131.0 million of 3.2% senior notes secured by approximately 111 MW of utility-scale wind power plants located in the United States. We used the net proceeds of this debt to repay a portion of the balance outstanding under the Revolver.

On September 25, 2019, we entered into a $475.0 million new non-recourse senior term loan (“Bridge Facility”) secured by the approximately 320 MW portfolio of distributed generation power facilities located in the U.S. that were acquired from subsidiaries of AltaGas. The Bridge Facility bears interest at a rate per annum equal to LIBOR plus an applicable margin of 100 basis points for the first six months, 150 basis points for the following six months and 175 basis points thereafter. We used the net proceeds of this debt to fund a portion of the purchase price of the WGL Acquisition. See Note 3. Acquisitions and Divestitures to our consolidated financial statements for additional details. The Bridge Facility matures on September 24, 2020. We have a one-year extension option and intend to complete a refinancing of the balance on a long-term basis before maturity in a series of two or more transactions.

On November 25, 2019, we entered into a new non-recourse debt financing agreement issuing $171.5 million of 3.55% senior notes secured by approximately 200.6 MW utility-scale wind power plants located in the U.S. We used the net proceeds of this debt to (i) redeem, in full, the outstanding balance of the non-recourse project term debt previously incurred by the subsidiary, of which $69.1 million remained outstanding plus accrued and unpaid interest, (ii) redeem, in full, derivative

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liabilities related to interest rate swaps with hedge counterparties of which $9.8 million remained outstanding and (iii) pay for the fees and expenses related to the issuance. We used the remaining proceeds for general corporate purposes.

2019 Spain Project Financings

On December 10, 2019, five of our subsidiaries completed a €235.8 million refinancing agreement (equivalent to $264.4 million at the closing date) of certain non-recourse indebtedness associated with 236.0 MW utility-scale wind plants located in Spain. These loans bear interest at a rate per annum equal to three months Euribor plus an applicable margin of 165 basis points that increases by 20 basis points every five years throughout maturity. We entered into interest rate swap agreements with counterparties to hedge approximately 80% of the cash flows associated with the debt, paying a fixed rate of 1.55%. In return, the counterparties agreed to pay the variable interest payments to the lenders. We used the net proceeds of the refinancing to fund a portion of the purchase price of the X-Elio PV Acquisition.

On December 27, 2019, we completed a €213.6 million refinancing agreement of certain non-recourse indebtedness, representing an upsize of approximately €42.0 million (equivalent to $239.5 million and $47.1 million at the closing date, respectively), of certain non-recourse indebtedness associated with approximately 50.0 MW concentrated solar power facility located in Spain (the “Spanish Solar Term Loans”). The Spanish Solar Term Loans consist of €146.4 million variable-rate tranche and €67.2 million fixed-rate tranche (equivalent to $164.2 million and $75.3 million, respectively). The variable-rate tranche bears interest at a rate per annum equal to three months Euribor plus an applicable margin of 190 basis points that increases by 20 basis points every five years throughout the maturity in December of 2033. The fixed-rate tranche bears interest at a rate of 2.55% and matures on June 30, 2035. The Spanish Solar Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through 2035. We entered into interest rate swap agreements with counterparties to hedge approximately 80% of the variable cash flows of the debt, paying an average fixed rate of 3.70%. In return, the counterparty agreed to pay the variable interest payments to the lenders. We used the net proceeds of the refinancing for general corporate purposes.

2019 Uruguay Project Financing

On April 30, 2019, two of our subsidiaries completed a $204.0 million refinancing agreements of certain non-recourse indebtedness, representing a net upsize of approximately $72.2 million, associated with 95 MW of utility-scale wind plants located in Uruguay consisting of a $103.0 million Tranche A loan, a new $72.0 million Tranche B loan, and an additional $29.0 million senior secured term loan. Approximately 46% of the combined principal amount of these loans bears a fixed interest rate of 2.6%, and the remainder bears interest at a rate per annum equal to six-month U.S. LIBOR plus an applicable margin that ranges from 1.94% to 2.94%. We entered into interest rate swap agreements with a counterparty to hedge greater than 90% of the cash flows associated with the variable portion of the debt, paying a fixed rate of 2.78%. In return, the counterparty agreed to pay the variable interest payments to the lenders. The net proceeds of the refinancing were used to pay down a portion of the Revolver and general corporate purposes.

See Note 10. Long-term Debt to our consolidated financial statements for further discussion of these financing activities.

Debt Service Obligations

We remain focused on refinancing near-term facilities on acceptable terms and maintaining a manageable maturity ladder. We do not anticipate material issues in addressing our borrowings through 2023 on acceptable terms and will do so opportunistically based on the prevailing interest rate environment.

The aggregate contractual principal payments of long-term debt due after December 31, 2019, including financing lease obligations and excluding amortization of debt discounts, premiums and deferred financing costs, as stated in the financing agreements, are as follows:

(In thousands)	20202		2021		2022		2023		2024		Thereafter		Total
Maturities of long-term debt1	$	745,755	$	276,331	$	440,294	$	774,586	$	282,581	$	3,768,922	$	6,288,469

—————

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(1)Represents the contractual principal payment due dates for our long-term debt, including our financing lease obligations, and does not reflect the reclassification of $159.3 million of long-term debt to current as a result of debt defaults under certain of our non-recourse financing arrangements (see Note 10. Long-term Debt to our consolidated financial statements for further discussion).

(2)Includes the $474.6 million Bridge Facility we entered into on September 25, 2019. The balance, net of unamortized deferred financing costs, is included within non-current liabilities in the consolidated balance sheets. See Note 10. Long-term Debt to our consolidated financial statements for additional details.

Incentive Distribution Rights

Prior to the consummation of the Merger, IDRs represented the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of Terra LLC’s quarterly distributions after the Class A Units of Terra LLC received quarterly distributions in an amount equal to $0.2257 per unit and the target distribution levels were achieved. SunEdison held 100% of the IDRs from the completion of the IPO up until the consummation of the Merger, at which point all IDRs were transferred to the Brookfield IDR Holder, an indirect, wholly-owned subsidiary of Brookfield.

Under Terra LLC’s limited liability company agreement (as amended from time to time, the “Terra LLC Agreement”), the IDR threshold for a first distribution is $0.93 per share of Common Stock and for a second distribution is $1.05 per share of Common Stock. Under the Terra LLC Agreement, amounts distributed from Terra LLC are to be distributed on a quarterly basis as follows:

•first, to the Company in an amount equal to the Company’s outlays and expenses for such quarter;

•second, to holders of Class A units, until an amount has been distributed to such holders of Class A units that would result, after taking account of all taxes payable by the Company in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Common Stock of $0.93 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Common Stock) if such amount were distributed to all holders of shares of Common Stock;

•third, 15% to the holders of the IDRs and 85% to the holders of Class A units until a further amount has been distributed to holders of Class A units in such quarter that would result, after taking account of all taxes payable by the Company in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Common Stock of an additional $0.12 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Common Stock) if such amount were distributed to all holders of shares of Common Stock; and

•thereafter, 75% to holders of Class A units and 25% to holders of the IDRs.

There were no IDR payments made by us during the years ended December 31, 2019 and 2018.

Changes in Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and money market funds, including restricted cash, with original maturity periods of three months or less when purchased.

Restricted cash consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements and funds held within our project companies that are restricted for current debt service payments and other purposes in accordance with the applicable debt agreements. These restrictions include: (i) cash on deposit in collateral accounts, debt service reserve accounts and maintenance reserve accounts; and (ii) cash on deposit in operating accounts but subject to distribution restrictions related to debt defaults existing as of the date of the balance sheet. Restricted cash that is not expected to become unrestricted within twelve months from the date of the balance sheet is presented within non-current assets.

The following table reflects the changes in our cash and cash equivalents, including restricted cash, as of December 31, 2019, and 2018:

	December 31,
(In thousands)	2019		2018		Change
Cash and cash equivalents	$	237,480	$	248,524	$	(11,044)
Restricted cash, current	35,657		27,784		7,873
Restricted cash - non-current	76,363		116,501		(40,138)
Total Cash and cash equivalents and restricted cash	$	349,500	$	392,809	$	(43,309)

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Cash Flow Discussion

We use traditional measures of cash flow, including net cash flows from operating activities, investing activities and financing activities for the evaluation of our periodic cash flow results.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

The following table reflects the changes in cash flows for the comparative periods:

(In thousands)	Year Ended December 31,
	2019		2018		Change
Net cash provided by operating activities	$	328,444	$	253,201	$	75,243
Net cash used in investing activities	(774,633)		(858,998)		84,365
Net cash provided by financing activities	406,812		782,501		(375,689)

Net Cash Provided by Operating Activities

Net cash provided by operating activities for the year ended December 31, 2019, was $328.4 million as compared to $253.2 million for the same period in the prior year. The increase in operating cash flow of $75.2 million was primarily driven by a $183.2 million increase in operating revenues for the period (excluding losses on commodity derivative contracts, recognition of deferred revenue and amortization of favorable and unfavorable rate revenue contracts, net). Total operating costs (excluding non-cash items) increased by $45.3 million for the year ended December 31, 2019 compared to 2018. The $137.9 million net increase in cash earnings for the year ended December 31, 2019 compared to 2018, was primarily driven by contributions from our European Platform. This increase in operating cash flows was partially offset by $17.7 million net decrease due to the timing of sales and collections from customers and payment of vendors, $43.4 million increase in interest payments, $1.6 million increase in income tax payments.

Net Cash Used in Investing Activities

Net cash used in investing activities for the year ended December 31, 2019, was $774.6 million, which consisted of (i) $731.8 million payments to acquire approximately 320 MW portfolio of distributed generation facilities in the U.S. from subsidiaries of AltaGas, and 45 MW solar PV facilities in Spain from subsidiaries of X-Elio Energy, net of cash and restricted cash acquired, (ii) $73.7 million payments to acquire renewable energy facilities from third parties in the U.S., net of cash and restricted cash acquired and (iii) $21.2 million payments for capital expenditures. These payments were partially offset by (i) $29.8 million net proceeds from the settlement of foreign currency contracts used to hedge the exposure associated with foreign subsidiaries, (ii) $5.1 million proceeds received from a government rebate for certain costs previously incurred for capital expenditures, (iii) $10.8 million net proceeds from the sale of renewable energy facilities in the U.S., and (iv) approximately $6.2 million received from other investing activities.

Net cash used in investing activities for the year ended December 31, 2018, was $859.0 million, which consisted of (i) $886.1 million of payments to acquire the shares of Saeta, net of cash and restricted cash acquired; (ii) $8.3 million payments to acquire solar facilities from third parties in the United States and Spain, net of cash and restricted cash acquired; (iii) the use of $22.4 million for capital expenditures; (iv) $47.6 million of proceeds from the settlement of foreign currency contracts used to hedge the exposure associated with foreign subsidiaries; (v) the receipt of $8.7 million of proceeds received from utilities rebates for certain costs previously incurred for capital expenditures; and (vi) the receipt of $1.5 million from insurance for reimbursement for the cost of property damages.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the year ended December 31, 2019 was $406.8 million, which consisted of (i) $298.8 million net proceeds received from public offering and private placement of our Common Stock, (ii) $53.5 million net proceeds from the refinancing of our corporate debt, and (iii) $1,267.2 million net proceeds from borrowings of non-recourse debt. These proceeds were partially offset by (i) $171.5 million distributions to our Class A common stockholders, (ii) $8.4 million repurchases of our Common Stock, (iii) $377.0 million net repayments on our Revolver, (iv) $557.1 million

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principal payments on our non-recourse debt, (v) $56.2 million payment for financing fees and termination costs, and (vi) $24.2 million net payments to non-controlling interests.

Net cash used in financing activities for the year ended December 31, 2018 was $782.5 million, which was primarily driven by $650.0 million proceeds received from the private placement to affiliates of Brookfield, net draws of $317.0 million on our Revolver that were partially offset by $135.2 million of distributions to our Class A common stockholders and net repayments of $22.8 million of non-recourse long-term debt.

Contractual Obligations and Commercial Commitments

We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements. The following table summarizes our outstanding contractual obligations and commercial commitments as of December 31, 2019:

	Payment due by Period
Contractual Cash Obligations (in thousands)	20202		2021		2022		2023		2024		Thereafter		Total
Long-term debt (principal)1	$	742,664	$	273,160	$	437,168	$	770,276	$	279,648	$	3,726,020	$	6,228,936
Long-term debt (interest)2	256,299		247,529		235,129		202,022		175,168		899,580		2,015,727
Financing lease obligations	3,091		3,171		3,126		4,310		2,933		42,902		59,533
Operating leases	21,921		21,828		22,046		22,220		22,424		319,532		429,971
Purchase obligations	47,233		44,371		45,203		46,054		45,907		246,860		475,628
Brookfield MSA5	15,614		15,927		16,245		16,570		16,902		N/A5		81,258
Energy tracking accounts, net	1,632		1,969		2,114		2,271		2,271		60,133		70,390
Other	2,795		1,886		1,857		364		230		11,596		18,728
Total contractual obligations	$	1,091,249	$	609,841	$	762,888	$	1,064,087	$	545,483	$	5,306,623	$	9,380,171

———

(1)Represents the contractual principal payment due dates for our long-term debt and does not reflect the reclassification of $9.8 million of non-current debt to current as a result of debt defaults under certain of our non-recourse financing arrangements (see Note 10. Long-term Debt to our consolidated financial statements for further discussion).

(2)Includes $474.6 million Bridge Facility maturing on September 24, 2020. We have a one-year extension option and intend to complete a refinancing of the balance on a long-term basis prior to maturity.

(3)Includes fixed rate interest and variable rate interest using December 31, 2019 rates.

(4)Consists of contractual payments due for third party O&M and asset management services.

(5)Represents the fixed component of the base management fee owed pursuant to the Brookfield MSA. We will be required to pay a base management fee with a fixed component of $3.75 million (adjusted for inflation) per quarter for each quarter in 2023 and beyond that Brookfield and certain of its affiliates provide management and administrative services to us. See Note 21. Related Parties to our consolidated financial statements for further discussion.

Off-Balance Sheet Arrangements

We enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. See Note 20. Commitments and Contingencies to our consolidated financial statements included in this Annual Report for additional discussion.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions in certain circumstances that affect amounts reported in our consolidated financial statements and related footnotes. In preparing these consolidated financial statements, we made our best estimates of certain amounts included in the consolidated financial statements. Application of accounting policies and estimates, however, involves the exercise of judgment and use of assumptions as to future uncertainties and, as a result, actual results could differ from these estimates. In arriving at our critical accounting estimates, factors we consider include how accurate the estimate or assumptions have been in the past, how much the estimate or assumptions have changed and how reasonably likely such change may have a material impact. Our critical accounting policies are discussed below.

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Business Combinations

We apply the definition of a business in ASC 805, Business Combinations to determine whether we are acquiring a business or a group of assets.

We account for business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interests in the acquiree at fair value at the acquisition date. We also recognize and measure the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, acquisition costs related to business combinations are expensed as incurred. Business combinations is a critical accounting policy as there are significant judgments involved in the allocation of acquisition cost.

When we acquire renewable energy facilities, we allocate the purchase price to (i) the acquired tangible assets and liabilities assumed, primarily consisting of land, plant, and long-term debt, (ii) the identified intangible assets and liabilities, primarily consisting of the value of favorable and unfavorable rate PPAs and REC agreements and the in-place value of market rate PPAs, (iii) non-controlling interests, and (iv) other working capital items based in each case on their fair values in accordance with ASC 805.

We generally engage independent appraisers to assist with the estimates and methodologies used such as a replacement cost approach, or an income approach or excess earnings approach. Factors considered by us in our analysis include considering current market conditions and costs to construct similar facilities. We also consider information obtained about each facility as a result of our pre-acquisition due diligence in estimating the fair value of the tangible and intangible assets and liabilities acquired or assumed. In estimating the fair value, we also establish estimates of energy production, current in-place and market power purchase rates, tax credit arrangements and operating and maintenance costs. A change in any of the assumptions above, which are subjective, could have a significant impact on the results of operations.

The allocation of the purchase price directly affects the following items in our consolidated financial statements:

•The amount of purchase price allocated to the various tangible and intangible assets, liabilities and non-controlling interests on our balance sheet;

•The amounts allocated to the value of favorable and unfavorable rate PPAs and REC agreements are amortized to revenue over the remaining non-cancelable terms of the respective arrangement. The amounts allocated to all other tangible assets and intangibles are amortized to depreciation or amortization expense, except for favorable and unfavorable rate land leases and unfavorable rate O&M contracts which are amortized to cost of operations; and

•The period of time over which tangible and intangible assets and liabilities are depreciated or amortized varies, and thus, changes in the amounts allocated to these assets and liabilities will have a direct impact on our results of operations.

ASC 805 allows the acquirer to report provisional amounts and adjust them for a period of time up to one year after the acquisition date (the “measurement period”) we obtain information about the facts and circumstances that existed as of the acquisition date.

When an acquired group of assets does not constitute a business, we account for the transaction as an asset acquisition. We recognize and measure the acquired assets based on the cost of the acquisitions, generally being the consideration transferred to the seller and typically includes the direct transaction costs related to the acquisition. We allocate the total cost of acquisition to the individual assets acquired or liabilities assumed based on their relative fair values generally similar to the allocation of the purchase price in a business combination. No goodwill is recognized in an asset acquisition.

Non-controlling Interests and HLBV

Non-controlling interests represent the portion of net assets in consolidated entities that are not owned by us and are reported as a component of equity in the consolidated balance sheets. Non-controlling interests in subsidiaries that are redeemable either at the option of the holder or at fixed and determinable prices at certain dates in the future are classified as redeemable non-controlling interests in subsidiaries between liabilities and stockholders’ equity in the consolidated balance sheets. Redeemable non-controlling interests that are currently redeemable or redeemable after the passage of time are adjusted to their redemption value as changes occur. We apply the guidance in ASC 810-10 along with the SEC guidance in ASC 480-10-S99-3A in the valuation of redeemable non-controlling interests.

We determined the allocation of economics between the controlling party and the third party for non-controlling

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interests does not correspond to ownership percentages for certain of its consolidated subsidiaries. In order to reflect the substantive profit sharing arrangements, we determined that the appropriate methodology for determining the value of non-controlling interests is a balance sheet approach using the HLBV method. Under the HLBV method, the amounts reported as non-controlling interest on the consolidated balance sheets represent the amounts the third party investors could hypothetically receive at each balance sheet reporting date based on the liquidation provisions of the respective operating partnership agreements. HLBV assumes that the proceeds available for distribution are equivalent to the unadjusted, stand-alone net assets of each respective partnership, as determined under U.S. GAAP. The third party non-controlling interests in the consolidated statements of operations and statements of comprehensive loss are determined based on the difference in the carrying amounts of non-controlling interests on the consolidated balance sheets between reporting dates, adjusted for any capital transactions between us and third party investors that occurred during the respective period. 

Where, prior to the commencement of operating activities for a respective renewable energy facility, HLBV results in an immediate change in the carrying value of non-controlling interest on the consolidated balance sheets due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, we defer the recognition of the respective adjustments and recognizes the adjustments in non-controlling interest on the consolidated statements of operations on a straight-line basis over the expected life of the underlying assets giving rise to the respective difference. Similarly, where we have acquired a controlling interest in a partnership and there is a resulting difference between the initial fair value of non-controlling interest and the value of non-controlling interest as measured using HLBV, we initially record non-controlling interest at fair value and amortize the resulting difference over the remaining life of the underlying assets. 

Impairment of Renewable Energy Facilities and Intangibles

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recognized when indicators of impairment are present and the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. We review our current activities, changes in the conditions of our renewable energy facilities and the market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a long-lived asset group, generally this is an individual renewable energy project, include a substantial and sustained decline in the trading price of our Common Stock, severe adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in forecasted operating revenues and earnings of our operating projects, and deterioration in the performance of our renewable energy facilities. An impairment charge is measured as the difference between a long lived asset group’s carrying amount and its fair value. The fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets, and present value techniques.

During the year ended December 31, 2019, we identified opportunities to repower two wind power plants in the Northeast with a combined nameplate capacity of 160 MW, by replacing certain components of the wind turbines with newer equipment while preserving the existing towers, foundation and balance of plant. We view repowering activities as opportunities to increase efficiency and extend the useful lives of existing renewable energy facilities. We performed impairment testing for these two wind power plants. We did not record any impairment losses since we determined that the expected undiscounted cash flows were greater than the net carrying amount of the related renewable energy facilities of $79.4 million as of December 31, 2019. If we determine that we will move forward with the repowering activities for one or both of these wind plants during the year 2020, we will revise the estimated remaining useful lives of certain components of the renewable energy facilities that will be replaced in the repowering activities and accelerate the recognition of depreciation expense to no later than the removal date.

During the year ended December 31, 2018, we recognized a $15.2 million impairment charge related to an operating project within our Enfinity portfolio due to the bankruptcy of a significant customer. During the year ended December 31, 2017, we recognized a $1.4 million impairment charge, related to our portfolio of residential rooftop solar assets. Impairment charges are reflected within impairment of renewable energy facilities in the consolidated statements of operations. See Note 6. Renewable Energy Facilities to our consolidated financial statements for additional details.

Impairment of Goodwill

Goodwill is tested annually for impairment at the reporting unit level during the fourth quarter or earlier upon the occurrence of certain events or substantive changes in circumstances. A reporting unit is either the operating segment level or one level below, which is referred to as a component. The level at which the impairment test is performed requires judgment as to whether the operations below the operating segment constitute a self-sustaining business or whether the operations are similar such that they should be aggregated for purposes of the impairment test.

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In assessing goodwill for impairment, we may elect to use a qualitative assessment to determine whether the existence of events or circumstances leads to a determination that it is more-likely-than-not that the fair value of our reporting units are less than their carrying amounts. If we determine that it is not more-likely-than-not that the fair value of our reporting units are less than their carrying amounts, we are not required to perform any additional tests in assessing goodwill for impairment. However, if we conclude otherwise or elect not to perform the qualitative assessment, then we are required to perform the quantitative impairment test. In January 2017, guidance was issued which simplifies the test for goodwill impairment by eliminating Step 2, the requirement to calculate the implied fair value of goodwill to measure a goodwill impairment charge. We early adopted this guidance, which is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019 on December 1, 2018.

Derivative Instruments

As part of our risk management strategy, we enter into derivative instruments for the purpose of reducing exposure to fluctuations in interest rates, foreign currency and commodity prices. We enter into interest rate swap agreements in order to hedge the variability of expected future cash interest payments. Foreign currency contracts are used to reduce risks arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of these practices is to minimize the impact of foreign currency fluctuations on operating results. We also enter into commodity contracts to hedge price variability inherent in energy sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot energy prices and stabilize estimated revenue streams.

We recognize our derivative instruments at fair value in the consolidated balance sheets, unless the derivative instruments qualify for the normal purchase normal sale scope exception to derivative accounting.

Derivatives that qualify and are designated for hedge accounting are classified as either hedges of the variability of

expected future cash flows to be received or paid related to a recognized asset or liability (cash flow hedge) or hedges of the

exposure to foreign currency of a net investment in a foreign operation (net investment hedges). We may also use derivative contracts outside the hedging program to manage foreign currency risk associated with intercompany loans. In all cases. we view derivative financial instruments as a risk management tool and, accordingly, do not use derivative instruments for trading or speculative purposes.

Depreciable Lives of Long-lived Assets

We have significant investments in renewable energy facility assets. These assets are generally depreciated on a straight-line basis over their estimated useful lives which range from 12 to 28 years for our solar generation facilities. The major components of our wind plants are depreciated on a straight-line basis over their weighted average estimated remaining useful life of 19 and 23 years as of December 31, 2018 and 2017, respectively.

The estimation of asset useful lives requires significant judgment. Changes in our estimated useful lives of renewable energy facilities could have a significant impact on our future results of operations. See Note 2. Summary of Significant Accounting Policies to our consolidated financial statements regarding depreciation and estimated service lives of our renewable energy facilities.

Recently Issued Accounting Standards

See Note 2. Summary of Significant Accounting Policies to our consolidated financial statements included in this Annual Report for disclosures concerning recently issued accounting standards. These disclosures are incorporated herein by reference. 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to several market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with our business or with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to are interest rate risk, foreign currency risk and commodity risk. We do not use derivative financial instruments for speculative purposes.

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Interest Rate Risk

As of December 31, 2019, the estimated fair value of our debt was $6,512.2 million and the carrying value of our debt was $6,235.4 million. We estimate that a hypothetical 100 basis points (“bps”), or 1%, increase or decrease in market interest rates would have decreased or increased the fair value of our long-term debt by $97.3 million and $107.2 million, respectively.

During the year ended December 31, 2019, our corporate-level debt consisted of the Senior Notes due 2023 (fixed rate), the Senior Notes due 2028 (fixed rate), and the Senior Notes due 2030 (fixed rate). Additionally, during the year ended December 31, 2019, we had an undrawn balance of $800.0 million available under the Revolver (variable rate) and $500.00 under the Sponsor Line (variable rate). A hypothetical increase or decrease in interest rates by 1% would have increased or decreased interest expense related to our Revolver and Term Loan by $2.5 million for the year ended December 31, 2019.

As of December 31, 2019, our non-recourse permanent financing debt was at both fixed and fixed rates. Approximately 38% of the $3,854.4 million balance had a variable interest rate and the remaining 62% of the balance had a variable interest rate. We have entered into interest rate derivatives to swap the majority of our variable rate non-recourse debt to a fixed rate. Although we intend to use hedging strategies to mitigate our exposure to interest rate fluctuations, we may not hedge all of our interest rate risk and, to the extent we enter into interest rate hedges, our hedges may not necessarily have the same duration as the associated indebtedness. Our exposure to interest rate fluctuations will depend on the amount of indebtedness that bears interest at variable rates, the time at which the interest rate is adjusted, the amount of the adjustment, our ability to prepay or refinance variable rate indebtedness when fixed rate debt matures and needs to be refinanced and hedging strategies we may use to reduce the impact of any increases in rates. We estimate that a hypothetical 100 bps, or 1%, increase or decrease in our variable interest rates pertaining to interest rate swaps not designated as hedges would have increased or decreased our earnings by $29.8 million or $32.0 million, respectively, for the year ended December 31, 2019.

Foreign Currency Risk

During the year ended December 31, 2019, we generated operating revenues in the United States (including Puerto Rico), Canada, Spain, Portugal, the United Kingdom, Chile and Uruguay, with our revenues being denominated in U.S. dollars, Euro, and Canadian dollars. The PPAs, O&M agreements, financing arrangements and other contractual arrangements relating to our current portfolio are generally denominated in the same currencies.

We use currency forward and option contracts in certain instances to mitigate the financial market risks of fluctuations in foreign currency exchange rates. We manage our foreign currency exposures through the use of these currency forward and option contracts to reduce risks arising from the change in fair value of certain assets and liabilities, including intercompany loans denominated in Euro.

We use foreign currency forward and option contracts to hedge portions of our net investment positions in certain subsidiaries with Euro and Canadian dollar functional currencies and to manage our overall foreign exchange risk. For instruments that are designated and qualify as hedges of net investments in foreign operations, the effective portion of the net gains or losses attributable to changes in exchange rates are recorded in foreign currency translation adjustments in accumulated other comprehensive income (“AOCI”). The recognition in earnings of amounts previously recorded in AOCI is limited to circumstances such as complete or substantial liquidation of the net investment in the hedged foreign operation. The change in fair value of derivative contracts intended to serve as economic hedges that are not designated as hedging instruments is reported as a component of earnings in the consolidated statements of operations. The objective of these practices is to minimize the impact of foreign currency fluctuations on our operating results. We estimate that a hypothetical 100 bps, or 1%, increase or decrease in Euros would have increased or decreased our earnings by $3.0 million or $3.5 million, respectively, for the year ended December 31, 2019. Cash flows from derivative instruments designated as net investment hedges and non-designated derivatives used to manage foreign currency risks associated with intercompany loans are classified as investing activities in the consolidated statements of cash flows. Cash flows from all other derivative instruments are classified as operating activities in the consolidated statements of cash flows.

Commodity Risk

For certain of our wind power plants, we may use long-term cash-settled swap agreements to economically hedge commodity price variability inherent in wind electricity sales arrangements. If we sell electricity generated by our wind power plants to an independent system operator market and there is no PPA available, then we may enter into a commodity swap to hedge all or a portion of the estimated revenue stream. These price swap agreements require periodic settlements, in which we receive a fixed-price based on specified quantities of electricity and we pay the counterparty a variable market price based on the same specified quantity of electricity. We estimate that a hypothetical 10% increase or decrease in electricity sales prices

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pertaining to commodity swaps not designated as hedges would have increased or decreased our earnings by $10.9 million or $11.9 million for the year ended December 31, 2019, respectively.

Liquidity Risk

Our principal liquidity requirements are to finance current operations, service debt and to fund cash distributions to investors. Changes in operating plans, lower than anticipated electricity sales, increased expenses, acquisitions or other events may cause us 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. Our ability to meet our debt service obligations and other capital requirements, including capital expenditures, as well as make acquisitions, will depend on our future operating performance which, in turn, will be subject to general economic, financial, business, competitive, legislative, regulatory and other conditions, many of which are beyond our control.

Concentration of Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties under the contractual obligations they are bound by. Our financial assets are typically subject to concentrations of credit risk and primarily consist of cash and cash equivalents, accounts receivable and derivative assets.

We are subject to concentrations of credit risk related to the cash and cash equivalents that may exceed the insurable limits in the related jurisdictions. We place our cash and cash equivalents with creditworthy financial institutions and, historically, did not experience any losses with regards to balances in excess of insured limits or as a result of other concentrations of credit risk.

We serve hundreds of customers in three continents, and, in the United States, our customers are spread across various states resulting in the diversification of our customer base. Notwithstanding this diversification, a significant portion of our offtake counterparties are government-backed entities and public utility companies, which has the potential to impact the our exposure to credit risk. We monitor and manage credit risk through credit policies that include a credit approval process and the use of credit mitigation measures such as having a diversified portfolio of creditworthy offtake counterparties. As of December 31, 2019, on a weighted-average basis (based on MW), our PPA counterparties had an investment grade credit rating. However, there are a limited number of offtake counterparties under offtake agreements in certain regions that we operate, and this concentration may impact the overall exposure to credit risk, either positively or negatively, in that the offtake counterparties may be similarly affected by changes in economic, industry or other conditions.

Our derivative instruments expose us to credit risk to the extent counterparties may be unable to meet the terms of the contractual arrangements. We seek to mitigate such risk by transacting with a group of creditworthy financial institutions and through the use of master netting arrangements.

See Note 24. Concentration of Credit Risk to our consolidated financial statements for additional details.

Item 8. Financial Statements and Supplementary Data.

The financial statements and schedules are listed in Part IV, Item 15. Exhibits, Financial Statement Schedules of this Annual Report and are incorporated by reference herein. Our selected quarterly financial data for each of the quarterly periods ended March 31, June 30, September 30 and December 31 in 2019 and 2018, are included in Note 25. Quarterly Financial Information (Unaudited) to our consolidated financial statements in this Annual Report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we that file or furnish under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our

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management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

In connection with the preparation of this Annual Report, we carried out an evaluation under the supervision of and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, as of December 31, 2019, of the effectiveness of the design and operation of our disclosure controls and procedures, as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2019, our disclosure controls and procedures were not effective because of the material weaknesses described below under “Management’s Report on Internal Control Over Financial Reporting.”

During 2019, we continued our efforts to remediate the material weaknesses. To address the material weaknesses described below, we performed additional analyses and other procedures to ensure that our consolidated financial statements were prepared in accordance with U.S. GAAP. Accordingly, our management believes that the consolidated financial statements included in this Annual Report on Form 10-K fairly present, in all material respects, our financial condition, results of operations and cash flows as of the dates, and for the periods presented, in conformity with U.S. GAAP.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP and includes policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with the appropriate authorizations of management and directors of the Company, and (iii) provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Management, including the Chief Executive Officer and Chief Financial Officer, has conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, based on the criteria in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on management’s assessment using these criteria, we concluded that, as of December 31, 2019, there were material weaknesses in our internal control over financial reporting, as further described below.

As permitted by SEC guidance, management has excluded from its assessment of internal control over financial reporting the internal controls related to the 320 MW distributed generation portfolio acquired on September 26, 2019. As of December 31, 2019, and for the year ended December 31, 2019, total assets and total operating revenues excluded from management’s assessment of internal control over financial reporting related to this portfolio represented approximately 8% and 1% of the Company’s consolidated total assets and total operating revenues, respectively.

A material weakness is a deficiency or a combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis.

2019 Remediation Activities

In 2018, in making its assessment, management concluded that there were material weaknesses in our internal control over financial reporting. In response to the material weaknesses identified in our Annual Report on Form 10-K for the year ended December 31, 2018, the Company performed the following remediation activities in 2019:

•In order to identify risks to the achievement of financial reporting objectives at all levels of the entity (e.g., subsidiary, division, operating unit and functional levels), we standardized the risk and control matrices that identify the financial reporting risks and developed detailed attributes and steps to be performed by the reviewer to mitigate those risks.

•We hired dedicated permanent personnel in highly technical areas of accounting and finance, with assigned responsibility and accountability for financial reporting processes and internal controls.

•We provided certain specialized and technical training to strengthen our skills to support our controllership function to increase the knowledge of highly complex or recent accounting standards of our personnel.

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•We implemented and continued to enhance the capabilities of a new financial consolidation system expected to automate and reduce our reliance on manual controls and end-user computing spreadsheets to produce accurate and timely information.

•We enhanced the review controls over our tax processes and completed the implementation of a tax-basis system for our renewable energy facilities to reduce our reliance on manual controls and end-user computing spreadsheets related to year-end tax controls.

•We enhanced the design of our quarterly analytics processes to assist us in identifying unusual transactions, amounts, ratios, or trends that may have financial statement ramifications.

•We revised our policies and procedures in accordance with the updated risk and control matrix for evaluating the completeness and accuracy of information derived from IT systems and end-user computing spreadsheets used in the performance of key controls.

As of December 31, 2019, we have implemented the following remedial actions with respect to the previously reported material weakness related to the completeness, existence, and accuracy of revenues, deferred revenue, and accounts receivable.

•We performed an evaluation of the revenue-related processes, implemented process improvements and refined our understanding of the risks of material misstatements for each revenue stream. We developed and implemented preventative and detective controls and related attributes to address those risks, and ensured the controls were operating effectively.

•We implemented a quarterly control to reconcile monthly revenue recognition by project and stream and implemented new controls to the validate generation and pricing data used to calculate revenue and accounts receivable.

•We developed controls to validate the completeness and accuracy of incentive revenue as well as wind and solar energy generation data, including meter validation, used to recognize revenue.

•We enhanced our revenue analytics performed at a portfolio level with lower thresholds based on the size and risk of the portfolio, and analyzed variances based on generation and other factors separately.

As a result of the design and implemented process improvements for revenue-related controls during 2019 and the sustained operating effectiveness of a suite of preventative and detective controls, we remediated the material weakness related to revenue, deferred revenue and accounts receivable as of December 31, 2019.

Material Weaknesses in Internal Control

While we believe that we have taken steps to improve our internal control over financial reporting, certain of these initiatives were only implemented in late 2019. This means that while certain internal control design improvements were implemented in late 2019, not enough time has passed for them to be considered fully operational and the full impact of these improved processes has not been realized as of December 31, 2019.

As of December 31, 2019, we concluded that we had the following material weaknesses in our internal control over financial reporting:

•The Company’s risk assessment process failed to fully address certain risks of material misstatements of the financial statements and as a result, the Company did not have effective review controls to mitigate those risks of material misstatements of significant accounts, including risks related to the completeness and accuracy of information derived from IT systems and end-user computing spreadsheets used in the performance of those controls.

•The Company did not have sufficient resources to have effective controls over the application of GAAP and accounting measurements related to significant accounts, transactions and related financial statement disclosures.

Due to the existence of the above material weaknesses, we concluded that our internal control over financial reporting was not effective as of December 31, 2019. These material weaknesses create a reasonable possibility that a material misstatement to the consolidated financial statements will not be prevented or detected on a timely basis.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2019 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report, which is included herein.

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Remediation Plan

Based on the 2019 remediation activities explained above, we have taken steps to improve our organizational capabilities around internal control over financial reporting. Since those initiatives were implemented later in the year, the full impact of these changes was not realized by December 31, 2019. Furthermore, there was insufficient time to demonstrate full remediation by December 31, 2019 of certain monthly and quarterly controls, revised based on the updated risk and control matrix.

We will continue to strengthen our internal control over financial reporting and are committed to ensuring that such controls are designed and operating effectively. We are implementing process and control improvements to address the above material weaknesses as follows:

•We will continue to implement additional functionalities in our consolidation, automated account reconciliation and treasury systems, each of which is expected to enhance and automate our processes to produce accurate and timely information and reduce our reliance on end-user computing spreadsheets. We plan on implementing a commodity/energy trading and risk management software to automate end-to-end commodities and energy trading, tracking and management. These system enhancements and related controls are expected to decrease our reliance on manual processes and make our control environment more sustainable.

•We will perform a robust assessment to ascertain the sufficiency and competency of resources and will continue to provide specialized/technical training to strengthen our skills to support our controllership function and monitor where additional training is required. We will implement additional system capabilities and enhance existing controls to support management’s assertions with respect to the completeness, accuracy and validity of complex accounting measurements on a timely basis.

•We will enhance our management oversight controls over our subsidiaries to ensure consistent policies and procedures across global entities.

We have made significant progress with the Company’s remediation plans and will continue to take measures in 2020 to remediate these material weaknesses. In addition, under the direction of the Audit Committee of the Board of Directors, we will continue to review and make necessary changes to the overall design of the Company’s internal control environment, as well as to refine policies and procedures to improve the overall effectiveness of internal control over financial reporting of the Company.

The material weaknesses in our internal control over financial reporting will not be considered remediated until the remediated controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We are continuing to make progress on remediating these material weaknesses. No system of controls, no matter how well designed and operated, can provide absolute assurance that the objectives of the system of controls will be met, and no evaluation of controls can provide absolute assurance that all control deficiencies or material weaknesses have been or will be detected. There is no assurance that the remediation will be fully effective. As described above, these material weaknesses have not been remediated as of the filing date of this Annual Report. If these remediation efforts do not prove effective and control deficiencies and material weaknesses persist or occur in the future, the accuracy and timing of our financial reporting may be adversely affected.

Changes in Internal Control over Financial Reporting

Management, together with our CEO and CFO, evaluated the changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2019. As outlined above, TerraForm Power remediated the previously reported material weakness related to controls over revenue, deferred revenue and accounts receivable as of December 31, 2019.

Other than changes described under Remediation Activities and Remediation Plan above, there have been no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended) during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

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Certain information required by Part III is omitted from this Annual Report because the Company will file with the SEC a definitive proxy statement pursuant to Regulation 14A in connection with the solicitation of proxies for the Company’s Annual Meeting of Stockholders (the “2020 Proxy Statement”), within 120 days after the end of the fiscal year covered by this Annual Report, and certain information included therein is incorporated herein by reference.

Item 10. Directors, Executive Officers and Corporate Governance.

The information required under this Item 10 will be included in our 2020 Proxy Statement and is incorporated by reference herein.

Item 11. Executive Compensation.

The information required under this Item 11 will be included in our 2020 Proxy Statement and is incorporated by reference herein.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required under this Item 12 will be included in our 2020 Proxy Statement and is incorporated by reference herein.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required under this Item 13 will be included in our 2020 Proxy Statement and is incorporated by reference herein.

Item 14. Principal Accounting Fees and Services.

The information required under this Item 14 will be included in our 2020 Proxy Statement and is incorporated by reference herein.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) The following documents are filed as a part of this report.

(1) Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm - Internal Control Over Financial Reporting	85
Report of Independent Registered Public Accounting Firm - Consolidated Financial Statements	87
Predecessor Report of Independent Registered Public Accounting Firm - Consolidated Financial Statements	91
Consolidated Statements of Operations	92
Consolidated Statements of Comprehensive Loss	93
Consolidated Balance Sheets	94
Consolidated Statements of Stockholders’ Equity	95
Consolidated Statements of Cash Flows	97
Notes to Consolidated Financial Statements	100
1. Nature of Operations and Organization	100
2. Summary of Significant Accounting Policies	101
3. Acquisitions and Divestitures	113
4. Revenue	118
5. Cash and Cash Equivalents	119
6. Renewable Energy Facilities	120
7. Intangible Assets, Net and Goodwill	121
8. Leases	123
9. Asset Retirement Obligations	125
10. Long-term Debt	126
11. Income Taxes	132
12. Derivatives	135
13. Fair Value of Financial Instruments	139
14. Other Financial Information	142
15. Variable Interest Entities	142
16. Stockholders’ Equity	143
17. Stock-Based Compensation	147
18. Non-Controlling Interests	149
19. Accumulated Other Comprehensive Income	151
20. Commitments and Contingencies	152
21. Related Parties	155
22. (Loss) Earnings Per Share	162
23. Segment Reporting	163
24. Concentration of Credit Risk	166
25. Quarterly Financial Information (Unaudited)	168
26. Subsequent Events	169

(2) Financial Statement Schedules:

The information required to be submitted in the Financial Statement Schedules for TerraForm Power, Inc. has either been shown in the financial statements or notes, or is not applicable or required under Regulation S-X; therefore, those schedules have been omitted.

(3) Exhibits:

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See Exhibit Index submitted as a separate section of this Annual Report on Form 10-K (“Annual Report”).

Item 16. Form 10-K Summary.

None.

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of TerraForm Power, Inc.

Opinion on Internal Control over Financial Reporting

We have audited TerraForm Power, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, because of the effect of the material weakness described below on the achievement of the objectives of the control criteria, TerraForm Power, Inc. and subsidiaries (the Company) has not maintained effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the 320 MW distributed generation portfolio acquired on September 26, 2019, which is included in the 2019 consolidated financial statements of the Company and constituted approximately 8% of consolidated total assets as of December 31, 2019 and approximately 1% of consolidated total operating revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of the 320 MW distributed generation portfolio acquired on September 26, 2019.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment:

•The Company’s risk assessment process failed to identify certain risks of material misstatement of the financial statements and as a result the Company did not have effective review controls to address those risks of material misstatement of significant accounts, including risks related to the completeness and accuracy of information derived from IT systems and end-user computing spreadsheets used in the performance of those controls.

•The Company did not have sufficient resources to have effective controls over the application of GAAP and accounting measurements related to certain significant accounts, transactions and related financial statement disclosures.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2019 consolidated financial statements of the Company. These material weaknesses were considered in determining the nature, timing and extent of audit tests applied in our audit of the 2019 consolidated financial statements, and this report does not affect our report dated March 17, 2020, which expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with

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generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

New York, New York

March 17, 2020

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of TerraForm Power, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of TerraForm Power, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We did not audit the 2018 financial statements of TERP Spanish Holdco, S.L., a wholly-owned subsidiary, which reflect total assets constituting 36% at December 31, 2018, and total revenues constituting 29% in 2018, of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for TERP Spanish Holdco, S.L., is based solely on the report of the other auditors.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 17, 2020 expressed an adverse opinion thereon.

Adoption of New Accounting Standards

As discussed in Note 2 to the consolidated financial statements, the Company changed its method for recognizing revenue as a result of the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), and the amendments in ASUs 2015-14, 2016-08, 2016-10 and 2016-12 effective January 1, 2018.

As discussed in Note 2 to the consolidated financial statements, the Company changed its accounting for leases in 2019 due to the adoption of the Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), and the amendments in ASU No. 2018-11 effective January 1, 2019.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors during 2018 provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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	Accounting for Acquisitions
Description of the Matter	As described in Note 3 to the consolidated financial statements, TerraForm Power acquired several domestic distributed generation portfolios of renewable energy facilities from WGL Energy Systems, Inc. and WGSW, Inc. for a purchase price of $735 million and acquired several solar photovoltaic renewable energy facilities from subsidiaries of X-Elio Energy, S.L., a Spanish corporation, for a total purchase price of approximately $71 million (collectively, the “2019 Acquisitions”). The Company also completed the acquisition accounting and recorded measurement period adjustments in connection with the 2018 acquisition of Saeta Yield, S.A. (the “2018 Acquisition”) during the year ended December 31, 2019. Auditing the Company’s accounting for the 2019 Acquisitions was complex due to the significant estimation required by management to determine the fair values of renewable energy facilities and identified intangible assets. Auditing the Company’s accounting for the measurement period adjustments for the 2018 Acquisition was complex due to the significant estimation required by management to determine the fair value of debt in international jurisdictions. The assumptions used to estimate the fair value of the renewable energy facilities and intangible assets included the replacement cost per megawatt, discount rate, and certain assumptions that form the basis of the prospective financial information (“PFI”) (e.g., current and future power pricing agreement rates and operational data). Further, determining the interest rates used in calculating the fair value of debt in international jurisdictions required a significant level of subjectivity as the resultant values were highly sensitive to the selected rates. These assumptions are forward looking and could be affected by future economic and market conditions.
How We Addressed the Matter in Our Audit	To test the fair value of the renewable energy facilities and intangible assets, our audit procedures included, among others, assessing the significant assumptions described above and testing the completeness and accuracy of the underlying data. For example, we evaluated the estimated cash flows based on future generation volume by comparing the estimated future generation volume to historical generation volume and comparing the forward power pricing to long term power purchase agreements or Spanish government regulated rates, as applicable. We involved our valuation specialists to assist in evaluating the significant assumptions, including replacement cost assumptions used to estimate the fair value of renewable energy facilities, discount rates, and valuation methodologies used in the Company’s models. To test the measurement period adjustments related to the fair value of debt in international jurisdictions, we performed audit procedures that included evaluating the Company’s valuation methodology and significant assumptions. For example, with the assistance of our valuation specialists, we compared the estimated credit spreads used in the valuation of the assumed debt instruments to market information, including corporate debt indices, and evaluated the effects of prepayment provisions within the debt arrangements on the calculated fair values.
	Level 3 Derivative Financial Instruments Fair Value Measurement
Description of the Matter	As described in Note 13 to the consolidated financial statements, as of December 31, 2019, the aggregate fair value of Level 3 derivative instruments was $59.3 million. The Company’s long-term physically-settled commodity contracts are considered Level 3 fair value measurements as they contain significant unobservable inputs. The Company uses a discounted cash flow valuation technique and an option model, when applicable to determine the fair value of its derivative assets. Auditing the fair value measurement of Level 3 derivative financial instruments was complex given the complexity of the model used to value the option component of the derivative instruments and the judgmental nature of the assumptions used as inputs into the valuation model. In particular, the Company used significant unobservable inputs such as the forward commodity prices based on forward commodity curves and implied volatilities for the option component.

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How We Addressed the Matter in Our Audit	To test the valuation of Level 3 derivative financial instruments, our audit procedures included, among others, evaluating the valuation methodologies used by the Company and testing significant inputs, estimates and the mathematical accuracy of the calculations. In certain instances, with the assistance of our valuation specialists, we independently determined the significant assumptions (including long-dated forward pricing and implied volatilities), calculated the resultant fair values and compared them to the Company’s estimates. We obtained forward prices from independent sources, including broker quotes and counterparty fair values, and evaluated the Company’s assumptions related to their forward curves and confirmed key inputs with counterparties. We also performed sensitivity analyses using independent sources of market data to evaluate the change in fair value of Level 3 derivative financial instruments that would result from changes in underlying assumptions.
	Impairment of Long-lived Assets
Description of the Matter	As described in Note 2 to the consolidated financial statements, the Company reviews long-lived assets that are held and used for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable (“impairment indicators”). When impairment indicators are identified, the Company is required to perform a recoverability test using an estimate of future undiscounted cash flows for the long-lived asset group to compare to the respective carrying amount to determine whether the asset group is recoverable. Auditing the Company’s identification of impairment indicators involved significant auditor judgment due to the many geographic, regulatory and economic environments in which the Company operates, which requires an evaluation of a wide variety of factors in the evaluation of potential impairment indicators. Additionally, when impairment indicators were present, auditing the Company's recoverability test involved a high degree of subjectivity as the estimates underlying the determination of undiscounted cash flows of the asset group were based on entity-specific assumptions about future performance and industry conditions. Significant assumptions used in the Company’s undiscounted cash flow estimates included energy generation forecasts and unobservable forward energy market prices. Further, the identified material weakness relating to the Company not having effective review controls over the completeness and accuracy of information derived from IT systems and end-user computing spreadsheets used in the performance of those controls affected our audit procedures in this area.
How We Addressed the Matter in Our Audit	To test the Company’s identification of impairment indicators, our audit procedures included, among others, making inquiries of management to understand changes in the businesses, reading industry journals or publications to independently identify adverse changes in the regulatory environments or the geographic areas and evaluating the completeness of management’s assessment and analysis of the identified changes and whether they represented impairment indicators. To test the Company's recoverability tests, our audit procedures included, among others, evaluating the significant assumptions and operating data used to estimate future undiscounted cash flows. For example, we compared the significant assumptions to power curves, current industry trends, historical generation volumes, and power purchase agreements. We also performed sensitivity analyses of the significant assumptions to evaluate the change in the undiscounted cash flow estimate that would result from changes in the assumptions. We also recalculated management's estimated undiscounted cash flows and compared them to the carrying value of the respective long-lived asset groups. To respond to the material weakness, we performed incremental audit procedures to assess the completeness and accuracy of data used in the recoverability tests. For example, we agreed energy prices used in the recoverability tests to power purchase agreements and evaluated the future undiscounted cash flows of the long-lived asset group by comparing them to historical revenue and expense trends.

89

	Measurement of non-controlling interests
Description of the Matter	As described in Note 2 to the consolidated financial statements, non-controlling interests represent the portion of net assets in consolidated entities that are not owned by the Company and are reported in the consolidated balance sheets. As of December 31, 2019, non-controlling interests totaled $605 million, redeemable non-controlling interests totaled $23 million, and net loss attributable to non-controlling interests and redeemable non-controlling interests (collectively, “non-controlling interests”) for the year ended December 31, 2019 was $46 million and $12 million, respectively. Auditing non-controlling interests was complex due to the number of unique substantive profit-sharing arrangements and the complexity involved in developing and maintaining the Hypothetical Liquidation at Book Value (“HLBV”) model for each partnership or similar agreement that is used to allocate the current period net income or loss between the Company and the non-controlling interest holders. Further, the earnings allocated to the non-controlling interest holders was sensitive to certain income tax-related inputs to the tax capital accounts that are used in the HLBV models. Further, the identified material weakness relating to the Company not having sufficient resources to have effective internal controls over the application of U.S. GAAP and accounting measurements related to significant accounts, transactions and related financial statement disclosures affected our audit procedures in this area.
How We Addressed the Matter in Our Audit	To test the measurement of non-controlling interests, our audit procedures included, among others, testing the measurement of the tax capital accounts used in the HLBV models, including verifying capital contributions and distributions to supporting documentation, evaluating the calculation and allocation of taxable income, and examining the HLBV models for compliance with the contractual provisions in the partnership or similar agreement. We tested the completeness and accuracy of the underlying data used in the HLBV models, including U.S. GAAP and income tax-related inputs. To respond to the material weakness, we involved tax subject matter professionals to assist in evaluating the calculation of the tax capital accounts in accordance with the Internal Revenue Code, as well as compliance with the contractual provisions in the partnership or similar agreement.
	Realizability of Deferred Tax Assets
Description of the Matter	As described in Note 11 to the consolidated financial statements, at December 31, 2019 the Company recorded gross deferred tax assets of $768 million, which were reduced by a valuation allowance of $414 million. Deferred tax assets are reduced by a valuation allowance if, based on the weight of all available evidence, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Auditing management’s assessment of realizability of deferred tax assets involved complex auditor judgment because determining whether the future taxable income expected to be generated from the reversal of existing taxable temporary differences is more likely than not to result in the realization of existing deferred tax assets required management to make interpretations of the tax law and assumptions about reversal patterns that may be affected by future events.
How We Addressed the Matter in Our Audit	To test the realizability of deferred tax assets, our audit procedures included, among others, testing the Company’s analysis of the reversal of existing taxable temporary differences. For example, we tested the completeness and accuracy of the underlying data and the appropriateness of significant inputs and assumptions including the estimated reversal patterns for the existing taxable temporary differences. We tested the completeness and measurement of the Company’s tax attributes related to net operating losses and interest deduction limitation carryforwards generated in the US and foreign jurisdictions. With the assistance of our tax professionals, we evaluated the net operating loss carryforward periods as well as the amount of future taxable income that can be reduced by net operating loss carryforwards after an ownership change under Section 382 of the Internal Revenue Code.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2018.

New York, New York

March 17, 2020

90

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors TerraForm Power, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows of TerraForm Power, Inc. and subsidiaries (the Company) for the year ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of its operations and its cash flows for year ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We served as the Company’s auditor from 2014 to 2017.

McLean, Virginia

March 7, 2018, except for the fourth paragraph in

Note 18, as to which the date is March 15, 2019

91

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Year Ended December 31,
	2019		2018		2017
Operating revenues, net	$	941,240	$	766,570	$	610,471
Operating costs and expenses:
Cost of operations	279,896		220,907		150,733
Cost of operations - affiliate	—		—		17,601
General and administrative expenses	81,063		87,722		139,874
General and administrative expenses - affiliate	28,070		16,239		13,391
Acquisition costs	3,751		7,721		—
Acquisition costs - affiliate	920		6,925		—
Impairment of renewable energy facilities	—		15,240		1,429
Depreciation, accretion and amortization expense	434,110		341,837		246,720
Total operating costs and expenses	827,810		696,591		569,748
Operating income	113,430		69,979		40,723
Other expenses (income):
Interest expense, net	298,142		249,211		262,003
Loss on modification and extinguishment of debt, net	26,953		1,480		81,099
Gain on foreign currency exchange, net	(12,726)		(10,993)		(6,061)
Gain on sale of renewable energy facilities	(2,252)		—		(37,116)
Other income, net	(2,000)		(4,102)		(3,258)
Total other expenses, net	308,117		235,596		296,667
Loss before income tax expense (benefit)	(194,687)		(165,617)		(255,944)
Income tax expense (benefit)	11,898		(12,290)		(19,641)
Net loss	(206,585)		(153,327)		(236,303)
Less: Net (loss) income attributable to redeemable non-controlling interests	(11,983)		9,209		1,596
Less: Net loss attributable to non-controlling interests	(45,918)		(174,916)		(77,745)
Net (loss) income attributable to Class A common stockholders	$	(148,684)	$	12,380	$	(160,154)
Weighted average number of shares:
Class A common stock - Basic and diluted	213,275		182,239		103,866
(Loss) earnings per share:
Class A common stock - Basic and diluted	$	(0.70)	$	0.07	$	(1.61)
Distribution declared per share:
Class A common stock	$	0.8056	$	0.7600	$	1.9400

92

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

	Year Ended December 31,
	2019		2018		2017
Net loss	$	(206,585)	$	(153,327)	$	(236,303)
Other comprehensive (loss) income, net of tax:
Foreign currency translation adjustments:
Net unrealized gain (loss) arising during the period	15,652		(9,517)		10,300
Reclassification of net realized loss into earnings1	—		—		14,741
Hedging activities:
Net unrealized (loss) gain arising during the period	(42,290)		198		17,612
Reclassification of net realized (gain) loss into earnings	(2,579)		(4,442)		(2,247)
Other comprehensive income, net of tax	(29,217)		(13,761)		40,406
Total comprehensive loss	(235,802)		(167,088)		(195,897)
Less comprehensive (loss) income attributable to non-controlling interests:
Net (loss) income attributable to redeemable non-controlling interests	(11,983)		9,209		1,596
Net loss attributable to non-controlling interests	(45,918)		(174,916)		(77,745)
Foreign currency translation adjustments	—		—		8,665
Hedging activities	(624)		(777)		5,992
Comprehensive loss attributable to non-controlling interests	(58,525)		(166,484)		(61,492)
Comprehensive loss attributable to Class A common stockholders	$	(177,277)	$	(604)	$	(134,405)

———

(1)Represents the reclassification of the accumulated foreign currency translation loss for almost the Company’s entire portfolio of solar power plants located in the United Kingdom, as the Company’s sale of these facilities was completed in the second quarter of 2017 as discussed in Note 3. Acquisitions and Divestitures. The pre-tax amount of $23.6 million was recognized within Gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

93

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

	As of December 31,
	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	237,480	$	248,524
Restricted cash	35,657		27,784
Accounts receivable, net	167,865		145,161
Due from affiliates	499		196
Prepaid expenses	13,514		13,116
Derivative assets, current	15,819		14,371
Deposit on acquisitions	24,831		—
Other current assets	57,682		52,033
Total current assets	553,347		501,185
Renewable energy facilities, net, including consolidated variable interest entities of $3,188,508 and $3,064,675 in 2019 and 2018, respectively	7,405,461		6,470,026
Intangible assets, net, including consolidated variable interest entities of $690,594 and $751,377 in 2019 and 2018, respectively	1,793,292		1,996,404
Goodwill	127,952		120,553
Restricted cash	76,363		116,501
Derivative assets	57,717		90,984
Other assets	44,504		34,701
Total assets	$	10,058,636	$	9,330,354
Liabilities, Redeemable Non-controlling Interests and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt and financing lease obligations, including consolidated variable interest entities of $55,089 and $64,251 in 2019 and 2018, respectively	$	441,951	$	464,332
Accounts payable, accrued expenses and other current liabilities	178,796		181,400
Due to affiliates	11,510		6,991
Derivative liabilities, current	33,969		35,559
Total current liabilities	666,226		688,282
Long-term debt and financing lease obligations, less current portion, including consolidated variable interest entities of $932,862 and $885,760 in 2019 and 2018, respectively	5,793,431		5,297,513
Operating lease obligations, less current portion, including consolidated variable interest entities of $138,816 in 2019	272,894		—
Asset retirement obligations, including consolidated variable interest entities of $116,159 and $86,457 in 2019 and 2018, respectively	287,288		212,657
Derivative liabilities	101,394		93,848
Deferred income taxes	194,539		178,849
Other liabilities	112,072		90,788
Total liabilities	7,427,844		6,561,937
Redeemable non-controlling interests	22,884		33,495
Stockholders’ equity:
Class A common stock, $0.01 par value per share, 1,200,000,000 shares authorized, 227,552,105 and 209,642,140 shares issued in 2019, and 2018, respectively	2,276		2,096
Additional paid-in capital	2,512,891		2,391,435
Accumulated deficit	(508,287)		(359,603)
Accumulated other comprehensive income	11,645		40,238
Treasury stock, 1,051,298 and 500,420 shares in 2019 and 2018	(15,168)		(6,712)
Total TerraForm Power, Inc. stockholders’ equity	2,003,357		2,067,454
Non-controlling interests	604,551		667,468
Total stockholders’ equity	2,607,908		2,734,922
Total liabilities, redeemable non-controlling interests and stockholders’ equity	$	10,058,636	$	9,330,354

94

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

																		Non-controlling Interests
	Class A Common Stock Issued			Class B Common Stock Issued			Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Income		Common Stock Held in Treasury							Accumulated Deficit		Accumulated Other Comprehensive (Loss) Income				Total Equity
	Shares	Amount		Shares	Amount								Shares	Amount		Total		Capital						Total
Balance as of December 31, 2016	92,477	$	920	48,202	$	482	$	1,467,108	$	(227,050)	$	22,912	(254)	$	(4,025)	$	1,260,347	$	1,792,295	$	(308,742)	$	(14,406)	$	1,469,147	$	2,729,494
Net SunEdison investment	—	—		—	—		7,019		—		—		—	—		7,019		2,749		—		—		2,749		9,768
Equity reallocation	—	—		—	—		8,780		—		—		—	—		8,780		(8,780)		—		—		(8,780)		—
SunEdison exchange	48,202	482		(48,202)	(482)		641,452		—		(643)		—	—		640,809		(835,662)		194,210		643		(640,809)		—
Issuance of Class A common stock to SunEdison	6,493	65		—	—		(65)		—		—		—	—		—		—		—		—		—		—
Write-off of payables to SunEdison	—	—		—	—		15,677		—		—		—	—		15,677		—		—		—		—		15,677
Stock-based compensation	1,414	19		—	—		14,689		—		—		(246)	(2,687)		12,021		—		—		—		—		12,021
Net loss	—	—		—	—		—		(160,154)		—		—	—		(160,154)		—		(77,745)		—		(77,745)		(237,899)
Special Distribution payment	—	—		—	—		(285,497)		—		—		—	—		(285,497)		—		—		—		—		(285,497)
Other comprehensive income	—	—		—	—		—		—		25,749		—	—		25,749		—		—		14,657		14,657		40,406
Sale of membership interests and contributions from non-controlling interests	—	—		—	—		—		—		—		—	—		—		6,935		—		—		6,935		6,935
Distributions to non-controlling interests	—	—		—	—		—		—		—		—	—		—		(23,345)		—		—		(23,345)		(23,345)
Deconsolidation of non-controlling interest	—	—		—	—		—		—		—		—	—		—		(8,713)		—		—		(8,713)		(8,713)
Accretion of redeemable non-controlling interest	—	—		—	—		(6,729)		—		—		—	—		(6,729)		—		—		—		—		(6,729)
Reclassification of Invenergy Wind Interest from redeemable non-controlling interests to non-controlling interests	—	—		—	—		—		—		—		—	—		—		131,822		—		—		131,822		131,822
Other	—	—		—	—		9,691		—		—		—	—		9,691		—		(5,919)		—		(5,919)		3,772
Balance as of December 31, 2017	148,586	$	1,486	—	$	—	$	1,872,125	$	(387,204)	$	48,018	(500)	$	(6,712)	$	1,527,713	$	1,057,301	$	(198,196)	$	894	$	859,999	$	2,387,712
Cumulative-effect adjustment1	—	—		—	—		—		15,221		5,193		—	—		20,414		—		(308)		—		(308)		20,106
Issuances of Class A common stock to affiliates	61,056	610		—	—		650,271		—		—		—	—		650,881		—		—		—		—		650,881
Stock-based compensation	—	—		—	—		257		—		—		—	—		257		—		—		—		—		257
Net income (loss)	—	—		—	—		—		12,380		—		—	—		12,380		—		(174,916)		—		(174,916)		(162,536)
Distribution	—	—		—	—		(135,234)		—		—		—	—		(135,234)		—		—		—		—		(135,234)
Other comprehensive loss	—	—		—	—		—		—		(12,984)		—	—		(12,984)		—		—		(777)		(777)		(13,761)
Contributions from non-controlling interests	—	—		—	—		—		—		—		—	—		—		7,685		—		—		7,685		7,685
Distributions to non-controlling interests	—	—		—	—		—		—		—		—	—		—		(24,128)		—		—		(24,128)		(24,128)
Purchase of redeemable non-controlling interests	—	—		—	—		817		—		—		—	—		817		—		—		—		—		817
Other	—	—		—	—		3,199		—		11		—	—		3,210		(87)		—		—		(87)		3,123
Balance as of December 31, 2018	209,642	$	2,096	—	$	—	$	2,391,435	$	(359,603)	$	40,238	(500)	$	(6,712)	$	2,067,454	$	1,040,771	$	(373,420)	$	117	$	667,468	$	2,734,922

95

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(CONTINUED)

																		Non-controlling Interests
	Class A Common Stock Issued			Class B Common Stock Issued			Additional Paid-in Capital		Accumulated Deficit		Accumulated Other Comprehensive Income		Common Stock Held in Treasury							Accumulated Deficit		Accumulated Other Comprehensive (Loss) Income				Total Equity
	Shares	Amount		Shares	Amount								Shares	Amount		Total		Capital						Total
Balance as of December 31, 2018	209,642	$	2,096	—	$	—	$	2,391,435	$	(359,603)	$	40,238	(500)	$	(6,712)	$	2,067,454	$	1,040,771	$	(373,420)	$	117	$	667,468	$	2,734,922
Issuances of Class A common stock, net of issuance costs	17,889	179		—	—		298,589		—		—		—	—		298,768		—		—		—		—		298,768
Purchase of treasury stock	—	—		—	—		—		—		—		(543)	(8,353)		(8,353)		—		—		—		—		(8,353)
Stock-based compensation	21	1		—	—		492		—		—		(8)	(103)		390		—		—		—		—		390
Net loss	—	—		—	—		—		(148,684)		—		—	—		(148,684)		—		(45,918)		—		(45,918)		(194,602)
Distributions to Class A common stockholders	—	—		—	—		(171,503)		—		—		—	—		(171,503)		—		—		—		—		(171,503)
Other comprehensive loss	—	—		—	—		—		—		(28,593)		—	—		(28,593)		—		—		(624)		(624)		(29,217)
Contributions from non-controlling interests	—	—		—	—		—		—		—		—	—		—		6,356		—		—		6,356		6,356
Distributions to non-controlling interests	—	—		—	—		—		—		—		—	—		—		(25,366)		—		—		(25,366)		(25,366)
Purchase of non-controlling interests	—	—		—	—		(687)		—		—		—	—		(687)		(393)		—		—		(393)		(1,080)
Non-cash redemption of redeemable non-controlling interests	—	—		—	—		(7,345)		—		—		—	—		(7,345)		—		—		—		—		(7,345)
Purchase of redeemable non-controlling interests	—	—		—	—		1,910		—		—		—	—		1,910		—		—		—		—		1,910
Non-controlling interests acquired in business combination	—	—		—	—		—		—		—		—	—		—		3,028		—		—		3,028		3,028
Balance as of December 31, 2019	227,552	$	2,276	—	—		$	2,512,891	$	(508,287)	$	11,645	(1,051)	$	(15,168)	$	2,003,357	$	1,024,396	$	(419,338)	$	(507)	$	604,551	$	2,607,908

———

(1)Represents the effect of the adoption of Accounting Standards Update (“ASU”) No. 2014-09, ASU No. 2016-08, ASU No. 2017-12 and ASU No. 2018-02 as of January 1, 2018.

96

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2019		2018		2017
Cash flows from operating activities:
Net loss	$	(206,585)	$	(153,327)	$	(236,303)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, accretion and amortization expense	434,110		341,837		246,720
Amortization of favorable and unfavorable rate revenue contracts, net	39,940		38,767		39,576
Loss on modification and extinguishment of debt, net	26,953		1,480		81,099
Gain on sale of renewable energy facilities	(2,252)		—		(37,116)
Impairment of renewable energy facilities	—		15,240		1,429
Loss on disposal of renewable energy facilities	15,483		6,231		5,828
Amortization of deferred financing costs, debt discounts, and premiums	14,224		11,009		23,729
Unrealized (gain) loss on interest rate swaps	(4,658)		(13,116)		2,425
(Reductions) charges to allowance for doubtful accounts, net	(4,239)		4,510		339
Unrealized loss on commodity contract derivatives, net	14,036		4,497		6,847
Recognition of deferred revenue	(3,457)		(1,320)		(18,238)
Stock-based compensation expense	492		257		16,778
Gain on foreign currency exchange, net	(11,480)		(12,899)		(5,583)
Deferred taxes	6,983		(14,891)		(19,911)
Other, net	231		—		254
Changes in assets and liabilities, excluding the effect of acquisitions and divestitures:
Accounts receivable	(8,310)		12,569		(2,939)
Prepaid expenses and other current assets	975		(5,512)		803
Accounts payable, accrued expenses and other current liabilities	(17,000)		(18,976)		(42,537)
Due to affiliates, net	4,215		3,023		3,968
Other, net	28,783		33,822		29
Net cash provided by operating activities	328,444		253,201		67,197
Cash flows from investing activities:
Capital expenditures	(21,184)		(22,445)		(8,392)
Proceeds from the settlement of foreign currency contracts, net	29,806		47,590		—
Proceeds from divestiture of renewable energy facilities, net of cash and restricted cash disposed	10,848		—		183,235
Proceeds from energy rebate and reimbursable interconnection costs	5,117		8,733		25,679
Payments to acquire businesses, net of cash and restricted cash acquired	(731,782)		(886,104)		—
Payments to acquire renewable energy facilities from third parties, net of cash and restricted cash acquired	(73,682)		(8,315)		—
Proceeds from insurance reimbursement	—		1,543		—
Other investing activities	6,244		—		5,750
Net cash (used in) provided by investing activities	(774,633)		(858,998)		206,272
Cash flows from financing activities:
Proceeds from issuance of Class A common stock, net of issuance costs	298,767		650,000		—

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TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(CONTINUED)

	Year Ended December 31,
	2019	2018	2017
Purchase of treasury stock	(8,353)	—	—
Proceeds from the Senior Notes due 2030	700,000	—	—
Repayment of Senior Notes due 2025	(300,000)	—	—
Proceeds from the Senior Notes due 2023, net	—	—	494,985
Repayment of the Old Senior Notes due 2023	—	—	(950,000)
Proceeds from the Senior Notes due 2028, net	—	—	692,979
Revolver draws	492,500	679,000	265,000
Revolver repayments	(869,500)	(362,000)	(205,000)
Old Revolver repayments	—	—	(552,000)
Proceeds from the Term Loan, net	—	—	344,650
Termination of the Term Loan	(343,875)	—	—
Term Loan principal repayments	(2,625)	(3,500)	—
Proceeds from borrowings of non-recourse long-term debt	792,216	236,251	79,835
Principal payments and prepayments on non-recourse long-term debt	(557,099)	(259,017)	(569,463)
Proceeds from the Bridge Facility	475,000	—	—
Proceeds from the Sponsor Line - affiliate	—	86,000	—
Repayments of the Sponsor Line - affiliate	—	(86,000)	—
Senior Notes prepayment penalties	(18,366)	—	(50,712)
Debt financing fees paid	(37,597)	(9,318)	(29,972)
Sale of membership interests and contributions from non-controlling interests	6,356	7,685	6,935
Purchase of membership interests and distributions to non-controlling interests	(30,509)	(29,163)	(31,163)
Net SunEdison investment	—	—	7,694
Due to affiliates, net	—	4,803	(8,869)
Cash distributions to Class A common stockholders	(171,503)	(135,234)	(285,497)
Payments to terminate interest rate swaps	(18,600)	—	—
Recovery of related party short-swing profit	—	2,994	—
Other financing activities	—	—	1,085
Net cash provided by (used in) financing activities	406,812	782,501	(789,513)
Net (decrease) increase in cash, cash equivalents and restricted cash	(39,377)	176,704	(516,044)
Net change in cash, cash equivalents and restricted cash classified within assets held for sale	—	—	54,806
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(3,932)	(8,682)	3,188

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TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(CONTINUED)

	Year Ended December 31,
	2019		2018		2017
Cash, cash equivalents and restricted cash at the beginning of the year	392,809		224,787		682,837
Cash, cash equivalents and restricted cash at the end of the year	$	349,500	$	392,809	$	224,787
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	294,145	$	250,734	$	260,685
Cash paid for income taxes	2,062		430		—
Schedule of non-cash activities:
Right-of-use assets recognized under Topic 842	$	262,142	$	—	$	—
Right-of-use liabilities recognized under Topic 842	256,015		—		—
Additions to renewable energy facilities in accounts payable and accrued expenses	1,455		4,000		1,622
Adjustment to ARO related to change in accretion period	27,917		(15,734)		—
ARO assets and obligations from acquisitions	33,143		68,441		—
Long-term debt assumed in connection with acquisitions	151,713		1,932,743		—
Write-off of payables to SunEdison to additional paid-in capital	—		—		15,677
Issuance of class A common stock to affiliates for settlement of litigation	—		881		—

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TERRAFORM POWER, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per share data, unless otherwise noted)

1. NATURE OF OPERATIONS AND ORGANIZATION

Nature of Operations

TerraForm Power, Inc. (“TerraForm Power” and, together with its subsidiaries, the “Company”) is a holding company and its primary asset is an equity interest in TerraForm Power, LLC (“Terra LLC”). TerraForm Power is the managing member of Terra LLC and operates, controls and consolidates the business affairs of Terra LLC, which through its subsidiaries owns and operates renewable energy facilities that have long-term contractual arrangements to sell the electricity generated by these facilities to third parties. The related green energy certificates, ancillary services and other environmental attributes generated by these facilities are also sold to third parties. The Company is sponsored by Brookfield Asset Management Inc. (“Brookfield”) and its primary business strategy is to acquire operating solar and wind assets in North America and Western Europe. The Company is a controlled affiliate of Brookfield. As of December 31, 2019, affiliates of Brookfield held approximately 62% of the Company’s Common Stock.

Brookfield Renewable Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal (the “Brookfield Proposal”) from Brookfield Renewable Partners L.P. (“Brookfield Renewable”), an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board of Directors of the Company (the “Board”) consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a special committee (the “Special Committee”) of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into a definitive agreement (the “Reorganization Agreement”) for Brookfield Renewable to acquire all of the Company’s outstanding shares of Common Stock, other than the approximately 62% currently owned by Brookfield Renewable and its affiliates (the transactions contemplated by the Reorganization Agreement, the “Transactions”). Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

The Consummation of the Brookfield Sponsorship Transaction and the Settlement with SunEdison

Prior to the consummation of the Merger (as defined below) on October 16, 2017, TerraForm Power was a controlled affiliate of SunEdison (together with its consolidated subsidiaries and excluding the Company and TerraForm Global, Inc. (“TerraForm Global”) and their subsidiaries, “SunEdison”). Upon the consummation of the Merger, a change of control of TerraForm Power occurred, and Orion US Holdings 1 L.P. (“Orion Holdings”), an affiliate of Brookfield, held 51% of the voting securities of TerraForm Power. As a result of the Merger, TerraForm Power is no longer a controlled affiliate of SunEdison and became a controlled affiliate of Brookfield. In June 2018, TerraForm Power closed a private placement to certain affiliates of Brookfield such that, as of December 31, 2018, affiliates of Brookfield held approximately 65% of TerraForm Power’s Common Stock. On October 8, 2019, the Company completed a public offering and a simultaneous private placement to certain affiliates of Brookfield of its Common Stock whereby as of December 31, 2019, the combined ownership of affiliates of Brookfield was approximately 62%.

On April 21, 2016, SunEdison and certain of its domestic and international subsidiaries (the “SunEdison Debtors”) voluntarily filed for protection under Chapter 11 of the U.S. Bankruptcy Code (the “SunEdison Bankruptcy”). In response to SunEdison’s financial and operating difficulties, the Company initiated a process for the exploration and evaluation of potential

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strategic alternatives for the Company, including potential transactions to secure a new sponsor or sell the Company, and a process to settle claims with SunEdison. This process resulted in the Company’s entry into a definitive Merger and Sponsorship Transaction agreement on March 6, 2017 with Orion Holdings and BRE TERP Holdings Inc. (“Merger Sub”), a wholly-owned subsidiary of Orion Holdings, each of which is an affiliate of Brookfield. At the same time, the Company and SunEdison also entered into a settlement agreement (the “Settlement Agreement”) and a voting and support agreement (the “Voting and Support Agreement”), to among other things, facilitate the closing of the Merger and the settlement of claims between the Company and SunEdison.

On October 6, 2017, the Merger Agreement was approved by the holders of a majority of the outstanding Class A shares of TerraForm Power, excluding SunEdison, Orion Holdings, any of their respective affiliates or any person with whom any of them has formed (and not terminated) a “group” (as such term is defined in the Securities Exchange Act of 1934 as amended, the “Exchange Act”) and by the holders of a majority of the total voting power of the outstanding shares of the Company’s common stock entitled to vote on the transaction. With these votes, all conditions to the merger transaction contemplated by the Merger Agreement were satisfied. On October 16, 2017, Merger Sub merged with and into TerraForm Power (the “Merger”), with TerraForm Power continuing as the surviving corporation in the Merger. Immediately following the consummation of the Merger, there were 148,086,027 Class A shares of TerraForm Power outstanding (which excludes 138,402 Class A shares that were issued and held in treasury to pay applicable employee tax withholdings for restricted stock units (“RSUs”) held by employees that vested upon the consummation of the Merger) and Orion Holdings held 51% of such shares. In addition, pursuant to the Merger Agreement, at or prior to the effective time of the Merger, the Company and Orion Holdings (or one of its affiliates), among other parties, entered into a suite of agreements providing for sponsorship arrangements, including a master services agreement, relationship agreement, governance agreement and a sponsor line of credit (the “Sponsorship Transaction”), as are more fully described in Note 10. Long-term Debt and Note 21. Related Parties.

Immediately prior to the effective time of the Merger, pursuant to the Settlement Agreement, SunEdison exchanged all of the Class B units held by SunEdison or any of its controlled affiliates in Terra LLC for 48,202,310 Class A shares of TerraForm Power, and as a result of this exchange, all shares of Class B common stock of TerraForm Power held by SunEdison or any of its controlled affiliates were automatically redeemed and retired. Pursuant to the Settlement Agreement, immediately following this exchange, the Company issued to SunEdison additional Class A shares such that immediately prior to the effective time of the Merger, SunEdison and certain of its affiliates held an aggregate number of Class A shares equal to 36.9% of the Company’s fully diluted share count (which was subject to proration based on the Merger consideration election results as discussed in Note 16. Stockholders’ Equity). SunEdison and certain of its affiliates also transferred all of the outstanding IDRs of Terra LLC held by SunEdison or certain of its affiliates to Brookfield IDR Holder at the effective time of the Merger. Under the Settlement Agreement, upon the consummation of the Merger, all agreements between the Company and the SunEdison Debtors were deemed rejected, subject to certain limited exceptions, without further liability, claims or damages on the part of the Company. The settlements, mutual release and certain other terms and conditions of the Settlement Agreement also became effective upon the consummation of the Merger, as more fully discussed in Note 21. Related Parties.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements represent the results of TerraForm Power, which consolidates Terra LLC through its controlling interest.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated.

The Company elected not to push-down the application of the acquisition method of accounting to its consolidated financial statements following the consummation of the Merger and the change of control that occurred, as discussed in Note 1. Nature of Operations and Organization.

Reclassifications

Certain prior period amounts that existed within the consolidated balance sheets as of December 31, 2018, have been reclassified to conform to the current period presentation. Specifically, the Company presented the balances of current and non-current derivative assets and liabilities, and prepaid expenses separately on the consolidated balance sheets. Additionally, the

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Company presented the balances of current and non-current deferred revenue as components of current and non-current other liabilities, as appropriate.

Use of Estimates

In preparing the consolidated financial statements, the Company uses estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements. Such estimates also affect the reported amounts of revenues, expenses, and cash flows during the reporting period. To the extent there are material differences between the estimates and actual results, the Company’s future results of operations would be affected.

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and money market funds with original maturity periods of three months or less when purchased.

Restricted Cash

Restricted cash consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements and funds held within the Company’s project companies that are restricted for current debt service payments and other purposes in accordance with the applicable debt agreements. These restrictions include: (i) cash on deposit in collateral accounts, debt service reserve accounts and maintenance reserve accounts; and (ii) cash on deposit in operating accounts but subject to distribution restrictions related to debt defaults existing as of the date of the balance sheet. Restricted cash that is not expected to become unrestricted within twelve months from the date of the balance sheet is presented within non-current assets in the consolidated balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are reported on the consolidated balance sheets, including both billed and unbilled amounts, and are adjusted for the allowance for doubtful accounts and any write-offs. The Company establishes an allowance for doubtful accounts to adjust its receivables to amounts considered to be ultimately collectible, and charges to the allowance are recorded within general and administrative expenses or cost of operations, as appropriate, in the consolidated statements of operations. The Company’s allowance for doubtful accounts is based on a variety of factors, including the length of time receivables are past due, significant one-time events, the financial health of its customers, and historical experience. The allowance for doubtful accounts was $1.4 million and $1.6 million as of December 31, 2019, and 2018, respectively, and charges (reductions) to the allowance recorded within general and administrative expenses for the years ended December 31, 2019, 2018 and 2017 were $0.2 million, $0.1 million and $(1.5) million, respectively. Accounts receivable are written off in the period in which the receivable is deemed uncollectible, and collection efforts have been exhausted. There were no write-offs of accounts receivable for the years ended December 31, 2019, 2018, and 2017.

Renewable Energy Facilities

Renewable energy facilities consist of solar generation and storage facilities and wind power plants that are stated at cost. Expenditures for major additions and improvements are capitalized, and minor replacements, maintenance, and repairs are charged to expense as incurred. Depreciation of the Company’s solar and storage facilities is recognized using the straight-line composite method over their estimated useful lives which ranged from 12 to 28 years and 23 to 30 years, as of December 31, 2019 and 2018, respectively. Under this method, the Company’s assets with similar characteristics and estimated useful lives are grouped and depreciated as a single unit. Depreciation of the Company’s wind power plant is calculated based on the major components of wind power plants and is recognized over the estimated periods during which these major components remain in service. The Company’s major components of wind power plants had remaining useful lives ranging from 8 to 36 years. As of December 31, 2019 and 2018, they had a weighted average remaining useful life of 19 and 21 years, respectively.

Construction in-progress represents the cumulative construction costs, including the costs incurred for the purchase of major equipment and engineering costs and any capitalized interest. Once the project achieves commercial operation, the Company reclassifies the amounts recorded in construction in progress to renewable energy facilities in service.

Finite-Lived Intangibles

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The Company’s finite-lived intangible assets and liabilities represent revenue contracts, consisting of long-term licensing agreements, power purchase contracts (“PPAs”), and renewable energy credits (“RECs”) that were obtained through third-party acquisitions. The revenue contract intangibles comprise favorable and unfavorable rate PPAs and REC agreements and the in-place value of market-rate PPAs. Intangible assets and liabilities that have determinable estimated lives are amortized on a straight-line basis over those estimated lives. Amortization of favorable and unfavorable rate revenue contracts is recorded within operating revenues, net in the consolidated statements of operations. Amortization expense related to the licensing contracts and in-place value of market-rate revenue contracts is recorded within depreciation, accretion and amortization expense in the consolidated statements of operations. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used up. The amounts and useful lives assigned to intangible assets acquired and liabilities assumed impact the amount and timing of future amortization.

Impairment of Renewable Energy Facilities and Intangibles

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recognized when indicators of impairment are present and the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. The Company review our current activities, changes in the conditions of our renewable energy facilities and the market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a long-lived asset group, generally this is an individual renewable energy project, include a substantial and sustained decline in the trading price of our Common Stock, severe adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in forecasted operating revenues and earnings of our operating projects, and deterioration in the performance of our renewable energy facilities. An impairment charge is measured as the difference between a long lived asset group’s carrying amount and its fair value. The fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets, and present value techniques.

During the year ended December 31, 2018, the Company recognized a $15.2 million non-cash impairment charge within its Solar reporting segment related to an operating project within a distributed generation portfolio due to the bankruptcy of a significant customer. During the year ended December 31, 2017, the Company recognized an impairment charge of $1.4 million, within impairment of renewable energy facilities in the consolidated statements of operations, on its 11.4 MW portfolio of residential rooftop solar assets that was classified as held for sale as of December 31, 2016, and subsequently sold in 2017. See Note 3. Acquisitions and Divestitures and Note 6. Renewable Energy Facilities for further discussion.

Goodwill

The Company evaluates goodwill for impairment at least annually on December 1. The Company performs an impairment test between scheduled annual tests if facts and circumstances indicate that it is more-likely-than-not that the fair value of a reporting unit that has goodwill is less than its carrying value. A reporting unit is either the operating segment level or one level below, which is referred to as a component. The level at which the impairment test is performed requires judgment as to whether the operations below the operating segment constitute a self-sustaining business or whether the operations are similar such that they should be aggregated for purposes of the impairment test. The Company defines its reporting units to be consistent with its operating segments.

The Company may first make a qualitative assessment of whether it is more-likely-than-not that a reporting unit’s fair value is less than its carrying value to determine whether it is necessary to perform the quantitative goodwill impairment test. The qualitative impairment test includes considering various factors, including macroeconomic conditions, industry and market conditions, cost factors, a sustained share price or market capitalization decrease, and any reporting unit specific events. If it is determined through the qualitative assessment that a reporting unit’s fair value is more-likely-than-not greater than its carrying value, the quantitative impairment test is not required. If the qualitative assessment indicates it is more-likely-than-not that a reporting unit’s fair value is not greater than its carrying value, the Company must perform the quantitative impairment test. The Company may also elect to proceed directly to the quantitative impairment test without considering such qualitative factors.

The quantitative impairment test is the comparison of the fair value of a reporting unit with its carrying amount, including goodwill. In accordance with the authoritative guidance over fair value measurements, the Company defines the fair value of a reporting unit as the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. The Company primarily uses the income approach methodology of valuation, which uses the discounted cash flow method to estimate the fair values of the Company’s reporting units. The Company does not believe that a cost approach is relevant to measuring the fair values of its reporting units.

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Significant management judgment is required when estimating the fair value of the Company’s reporting units, including the forecasting of future operating results, the discount rates and expected future growth rates that it uses in the discounted cash flow method of valuation, and in the selection of comparable businesses that are used in the market approach. If the estimated fair value of the reporting unit exceeds the carrying value assigned to that unit, goodwill is not impaired. If the carrying value assigned to a reporting unit exceeds its estimated fair value, the Company records an impairment charge based on the excess of the reporting unit’s carrying amount over its fair value. The impairment charge is limited to the amount of goodwill allocated to the reporting unit.

The Company performed a qualitative impairment test for the goodwill balance of $128.0 million, and concluded that the carrying amount of the related reporting units does not exceed its fair value. No goodwill impairment charges were recorded for the years ended December 31, 2019, 2018 and 2017.

Financing Lease Obligations

Certain of the Company’s assets were financed with sale-leaseback arrangements. Proceeds received from a sale-leaseback are treated using the financing method when the sale of the renewable energy facility is not recognizable. A sale is not recognized when the leaseback arrangements include a prohibited form of continuing involvement, such as an option or obligation to repurchase the assets under the Company’s master lease agreements. Under these arrangements, the Company does not recognize any profit until the sale is recognizable, which the Company expects to recognize at the end of the arrangement when the contract is canceled and the initial deposits received are forfeited by the financing party.

The Company is required to make rental payments throughout the leaseback arrangements. These payments are allocated between principal and interest payments using an effective yield method.

Deferred Financing Costs

Financing costs incurred in connection with obtaining senior notes and term financing are deferred and amortized over the maturities of the respective financing arrangements using the effective interest method and are presented as a direct deduction from the carrying amount of the related debt (see Note 10. Long-term Debt for additional details), except for the costs related to the Company’s revolving credit facilities, which are presented as a non-current asset on the consolidated balance sheets within other assets. As of December 31, 2019, 2018 and 2017, the Company had $10.8 million, $6.7 million, and $9.4 million, respectively, of unamortized deferred financing costs related to its revolving credit facilities.

Inventory

Inventory consists of spare parts and is recorded at the lower of the weighted average cost of purchase or net realizable value within other current assets in the consolidated balance sheets. Spare parts are expensed to cost of operations in the consolidated statements of operations or capitalized to renewable energy facilities when installed or used, as appropriate.

Asset Retirement Obligations

Asset retirement obligations are accounted for in accordance with Accounting Standards Codification (“ASC”) 410-20, Asset Retirement Obligations. Retirement obligations associated with renewable energy facilities included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, and for which the timing and/or method of settlement may be conditional on a future event. Asset retirement obligations are recognized at fair value in the period in which they are incurred, and a corresponding asset retirement costs are recognized within the related renewable energy facilities. Over time, the asset retirement cost is depreciated over the estimated useful life of the related renewable energy facility, and the asset retirement obligation is accreted to its expected future value.

The Company generally reviews its asset retirement obligations annually, based on its review of updated cost studies, as necessary, and its evaluation of cost escalation factors. The Company evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant the application of the updated estimates to the asset retirement obligations. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognized as an increase or a decrease in the asset retirement cost to the extent applicable.

Revenue from Contracts with Customers

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Adoption of Topic 606

On January 1, 2018, the Company adopted ASU No. 2014-09, Revenue from Contracts with Customers and ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (collectively referred to as “Topic 606”) for all revenue contracts in scope, which primarily included bundled energy and incentive sales through PPAs, individual REC sales, and upfront sales of federal and state incentive benefits recorded. The Company elected to use the contract modification practical expedient for purposes of computing the cumulative-effect adjustment recorded to the balances of stockholders’ equity as of January 1, 2018.

The Company evaluated the impact of Topic 606 as it relates to the individual sale of RECs. In certain jurisdictions, there may be a lag between physical generation of the underlying energy and the transfer of RECs to the customer due to administrative processes imposed by state regulations. Under the Company’s previous accounting policy, revenue was recognized as the underlying electricity was generated if the sale had been contracted with the customer. Based on the framework in Topic 606, for a portion of the existing individual REC sale arrangements where the transfer of control to the customer is determined to occur upon the transfer of the RECs, the Company currently recognizes revenue commensurate with the transfer of RECs to the customer as compared to the generation of the underlying energy under the previous accounting policy. Revenue recognition practices for the remainder of existing individual REC sale arrangements remain the same; that is, revenue is recognized based on the underlying generation of energy because the contracted RECs are produced from a designated facility and control of the RECs transfers to the customer upon generation of the underlying energy. The adoption of Topic 606, as it relates to the individual sale of RECs, resulted in an increase in accumulated deficit on January 1, 2018, of $20.5 million, net of tax, and net of $0.3 million and $4.5 million that were allocated to non-controlling interests and redeemable non-controlling interests, respectively. The adjustments for accumulated deficit and non-controlling interests are reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018, and the redeemable non-controlling interests adjustment is reflected within cumulative-effect adjustment in the redeemable non-controlling interests roll-forward presented in Note 18. Non-controlling Interests.

The Company evaluated the impact of Topic 606 as it relates to the upfront sale of investment tax credits (“ITCs”) through its lease pass-through fund arrangements. The amounts allocated to the ITCs were initially recorded as deferred revenue in the consolidated balance sheets, and subsequently, one-fifth of the amounts allocated to the ITCs was recognized annually as incentives revenue in the consolidated statements of operations based on the anniversary of each solar energy system’s placed-in-service date. The Company concluded that revenue related to the sale of ITCs through its lease pass-through arrangements should be recognized at the point in time when the related solar energy systems are placed in service. Previously, the Company recognized this revenue evenly over the five-year ITC recapture period. The Company concluded that the likelihood of a recapture event related to these assessments is remote. The adoption of Topic 606, as it relates to the upfront sale of ITCs, resulted in a decrease in accumulated deficit on January 1, 2018 of $40.9 million, net of tax, which is reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018. The impact on the Company’s results of operations for the year ended December 31, 2018 resulted in a decrease in non-cash deferred revenue recognition of $16.3 million.

PPA Rental Income

The majority of the Company’s energy revenue is derived from long-term PPAs accounted for as operating leases under ASC 840, Leases. Rental income under these lease agreements is recorded as revenue when the electricity is delivered to the customer. The Company adopted ASC 842, Leases on January 1, 2019, and elected certain of the practical expedients permitted in the issued standard, including the expedient that permits the Company to retain its existing lease assessment and classification.

Solar and Wind PPA Revenue

PPAs that are not accounted for under the scope of leases or derivatives are accounted for under Topic 606. The Company typically delivers bundled goods consisting of energy and incentive products for a singular rate based on a unit of generation at a specified facility over the term of the agreement. In these types of arrangements, the volume reflects total energy generation measured in Kilowatt hours (“kWhs”), which can vary period to period depending on system and resource availability. The contract rate per unit of generation (kWhs) is generally fixed at contract inception; however, certain pricing arrangements can provide for time-of-delivery, seasonal, or market index adjustment mechanisms over time. The customer is invoiced monthly equal to the volume of energy delivered multiplied by the applicable contract rate.

The Company considers bundled energy and incentive products within PPAs to be distinct performance obligations. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the

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performance obligation is satisfied under Topic 606. The Company views the sale of energy as a series of distinct goods that is substantially the same and has the same pattern of transfer measured by the output method. Although the Company views incentive products in bundled PPAs to be performance obligations satisfied at a point in time, measurement of satisfaction and transfer of control to the customer in a bundled arrangement coincides with a pattern of revenue recognition with the underlying energy generation. Accordingly, the Company applied the practical expedient in Topic 606 as the right to consideration corresponds directly to the value provided to the customer to recognize revenue at the invoice amount for its standalone and bundled PPA contracts.

Commodity Derivatives

The Company has certain revenue contracts within its wind fleet that are accounted for as derivatives under the scope of ASC 815, Derivatives and Hedging. Amounts recognized within operating revenues, net in the consolidated statements of operations consist of cash settlements and unrealized gains and losses representing changes in fair value for the commodity derivatives that are not designated as hedging instruments. See Note 12. Derivatives for further discussion.

Regulated Solar and Wind Energy Revenue

Regulated solar and wind includes revenue generated by Saeta’s solar and wind operations in Spain, which are subject to regulations applicable to companies that generate production from renewable sources for facilities located in Spain. While Saeta’s Spanish operations are regulated by the Spanish regulator, the Company has determined that the Spanish entities do not meet the criteria of a rate-regulated entity under ASC 980 Regulated Operations, since the rates established by the Spanish regulator are not designed to recover the entity’s costs of providing its energy generation services. Accordingly, the Company applied Topic 606 to recognize revenue for these customer contract arrangements. The Company has distinct performance obligations to deliver electricity, capacity, and incentives which are discussed below.

The Company has a performance obligation to deliver electricity and these sales are invoiced monthly at the wholesale market price (subject to adjustments due to regulatory price bands that reduce market risk). The Company transfers control of the electricity over time and the customer receives and consumes the benefit simultaneously. Accordingly, the Company applied the practical expedient in Topic 606 as the right to consideration corresponds directly to the value provided to the customer to recognize revenue at the invoice amount for electricity sales.

The Company has a stand-ready performance obligation to deliver capacity in the Spanish electricity market in which these renewable energy facilities are located. Proceeds received by the Company from the customer in exchange for capacity are determined by a remuneration on an investment per unit of installed capacity that is determined by the Spanish regulators. The Company satisfies its performance obligation for capacity under a time-based measure of progress and recognizes revenue by allocating the total annual consideration evenly to each month of service.

Regulated Solar and Wind Incentive Revenue

For the Company’s Spanish solar renewable energy facilities, the Company has identified a performance obligation linked to an incentive that is distinct from the electricity and capacity deliveries discussed above. For solar technologies under the Spanish market, the customer makes an operating payment per MWh which is calculated based on the difference of a standard cost and an expected market price, both, determined by the Spanish regulator. The customer is invoiced monthly equal to the volume of energy produced multiplied by the regulated rate. The performance obligation is satisfied when the Company generates electricity from the solar renewable facility. The Company recognizes revenue based on the amount invoiced each month.

Amortization of Favorable and Unfavorable Rate-Revenue Contracts

The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. Intangible amortization of certain revenue contracts acquired in business combinations (favorable and unfavorable rate PPAs and REC agreements) is recognized on a straight-line basis over the remaining contract term. The current period amortization for favorable rate revenue contracts is reflected as a reduction to operating revenues, net, and amortization for unfavorable rate revenue contracts is reflected as an increase to operating revenues, net. See Note 7. Intangible Assets, Net and Goodwill for additional details.

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Solar and Wind Incentive Revenue

The Company generates incentive revenue from individual incentive agreements relating to the sale of RECs and performance-based incentives to third-party customers that are not bundled with the underlying energy output. The majority of individual REC sales reflect a fixed quantity, fixed price structure over a specified term. The Company views REC products in these arrangements as distinct performance obligations satisfied at a point in time. Since the REC products delivered to the customer are not linked to the underlying generation of a specified facility, these RECs are recognized into revenue when delivered. The Company typically receives payment within 30 days of invoiced REC revenue.

For certain incentive contract arrangements, the quantity delivered to the customer is linked to a specific facility. The pattern of revenue recognition for these incentive arrangements is recognized over time coinciding with the underlying revenue generation from the related facility.

See Note 4. Revenue for additional disclosures.

Leases

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which primarily changes the lessee’s accounting for operating leases by requiring the recognition of lease right-of-use assets and lease liabilities. The guidance also eliminates previous real estate specific provisions. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842), Targeted Improvements, which amended the standard to give entities another option to apply the requirements of the standard in the period of adoption (January 1, 2019) or Effective Date Method. The Company adopted the new accounting guidance on January 1, 2019 using a modified retrospective approach reflecting the Effective Date Method of adoption in which the Company continued to apply the guidance in ASC 840, Leases to the comparable periods presented in the year of adoption.

The Company made the following elections provided under the standard:

•The package of practical expedients that permits the Company to retain its existing lease assessment and classification;

•The practical expedient that allows the Company to not evaluate existing and expired land easements;

•The practical expedient to not separate non-lease components in power purchase agreements (“PPAs”) in which the Company is the lessor in providing energy, capacity, and incentive products for a bundled fixed rate; and

•The Company elected not to apply the recognition requirements for short-term operating leases, defined as a term of twelve months or shorter, from the commencement date.

The Company evaluated the impact of Topic 842 as it relates to operating leases for land, buildings and equipment for which it is the lessee and reviewed its existing contracts for embedded leases. The adoption of the new standard resulted in the recognition of right-of-use assets and lease liabilities of approximately $262.1 million and $256.0 million, respectively, as of January 1, 2019, for operating leases, whereas the Company’s accounting for finance leases remained substantially unchanged.

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment. Leases with an initial term of twelve months or shorter are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. During the year ended December 31, 2019, the Company did not have any leases with an initial term of less than twelve months.

Operating lease right-of-use assets are included within renewable energy facilities, net, whereas right-of-use liabilities are included within accounts payable, accrued expenses and other current liabilities. Right-of-use assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. As the Company’s leases do not provide an implicit rate, the Company calculated an incremental borrowing rate by leveraging external transactions at comparable entities and internally available information to determine the present value of lease payments. The Company’s leases have remaining lease terms ranging from 5 to 41 years.

        The Company’s lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise any such options. Lease expense is recognized on a straight-line basis over the expected lease term. Although some of the Company’s leases contain lease and non-lease components, the Company applies the practical expedient to account for each lease component and non-lease component as a single lease component. Lease payments include fixed rent and taxes, where applicable, and exclude variable rental payments that include other operating expenses is recognized as incurred. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive

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covenants. The following tables outline the different components of operating leases and other terms and conditions of the lease agreements where the Company is the lessee.

As discussed above, a significant portion of the Company’s operating revenues are generated from delivering electricity and related products from owned solar and wind renewable energy facilities under PPAs in which the Company is the lessor. Revenue is recognized when electricity is delivered and is accounted for as rental income under the lease standard. The adoption of ASC 842 did not have an impact on the accounting policy for rental income from the Company’s PPAs in which it is the lessor. The Company elected the package of practical expedients available under ASC 842, which did not require the Company to reassess its lease classification from ASC 840. Additionally, the Company elected the practical expedient to not separate lease and non-lease components for lessors. This election allows energy (lease component) and environmental incentives or renewable energy certificates (non-lease components) under bundled PPAs to be accounted as a singular lease unit of account under ASC 842.

See Note 8. Leases for additional disclosures.

Income Taxes

The Company accounts for income taxes using the liability method, which requires it to use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

The Company reports certain of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company’s financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company’s consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using enacted tax rates that are expected to be in effect when the deferred tax liabilities are expected to be realized or settled. Many factors are considered when assessing the likelihood of future realization of deferred tax assets, including recent earnings within taxing jurisdictions, expectations of future taxable income, the carry forward periods available and other relevant factors. The Company believes it is more likely than not that the future reversal of existing taxable temporary differences will allow the Company to realize deferred tax assets, net of valuation allowances. A valuation allowance is recorded to reduce the net deferred tax assets to an amount that is more-likely-than-not to be realized. Tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties related to uncertain tax benefits as a component of income tax expense. Changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits are recorded to income tax expense in the period such determination is made.

The Company releases the taxes deferred in AOCI as the individual units of account (i.e., derivative instruments in a cash flow hedge or net investment hedge relationships) are terminated, extinguished, sold or substantially liquidated.

Adoption of ASU 2018-02

During the fourth quarter of 2018, the Company early adopted ASU No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income addressing certain stranded income tax effects in AOCI resulting from the U.S. government’s enactment of the Tax Cuts and Jobs Act (the “Tax Act”) on December 22, 2017. The adoption of ASU No. 2018-12 resulted in reclassifying $9.4 million of stranded tax effects on the net unrealized gains on derivatives designated as hedging instruments in a cash flow relationship from AOCI to accumulated deficit. The reclassification is reflected as an increase to accumulated deficit within the cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018, and an increase to the opening balance of AOCI as of January 1, 2018.

Variable Interest Entities

The Company assesses entities for consolidation in accordance with ASC 810. The Company consolidates variable interest entities (“VIEs”) in renewable energy facilities when determined to be the primary beneficiary. VIEs are entities that lack one or more of the characteristics of a voting interest entity (“VOE”). The Company has a controlling financial interest in a VIE when its variable interest or interests provide it with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

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VOEs are entities in which (i) the total equity investment at risk is sufficient to enable the entity to finance its activities independently and (ii) the equity holders have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the losses of the entity and the right to receive the residual returns of the entity. The usual condition for a controlling financial interest in a voting interest entity is ownership of a majority voting interest. If the Company has a majority voting interest in a voting interest entity, the entity is consolidated.

For the Company’s consolidated VIEs, the Company has presented on its consolidated balance sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of its consolidated VIEs for which creditors do not have recourse to the Company’s general assets outside of the VIE.

Non-controlling Interests and Hypothetical Liquidation at Book Value (“HLBV”)

Non-controlling interests represent the portion of net assets in consolidated entities that are not owned by the Company and are reported as a component of equity in the consolidated balance sheets. Non-controlling interests in subsidiaries that are redeemable either at the option of the holder or at fixed and determinable prices at certain dates in the future are classified as redeemable non-controlling interests in subsidiaries between liabilities and stockholders’ equity in the consolidated balance sheets. Redeemable non-controlling interests that are currently redeemable or redeemable after the passage of time are adjusted to their redemption value as changes occur. The Company applies the guidance in ASC 810-10 along with the Securities and Exchange Commission (“SEC”) guidance in ASC 480-10-S99-3A in the valuation of redeemable non-controlling interests.

The Company has determined the allocation of economics between the controlling party and the third party for non-controlling interests does not correspond to ownership percentages for certain of its consolidated subsidiaries. In order to reflect the substantive profit sharing arrangements, the Company has determined that the appropriate methodology for determining the value of non-controlling interests is a balance sheet approach using the HLBV method. Under the HLBV method, the amounts reported as non-controlling interest on the consolidated balance sheets represent the amounts the third party investors could hypothetically receive at each balance sheet reporting date based on the liquidation provisions of the respective operating partnership agreements. HLBV assumes that the proceeds available for distribution are equivalent to the unadjusted, stand-alone net assets of each respective partnership, as determined under U.S. GAAP. The third party non-controlling interests in the consolidated statements of operations and statements of comprehensive loss are determined based on the difference in the carrying amounts of non-controlling interests on the consolidated balance sheets between reporting dates, adjusted for any capital transactions between the Company and third party investors that occurred during the respective period. 

Where, prior to the commencement of operating activities for a respective renewable energy facility, HLBV results in an immediate change in the carrying value of non-controlling interests on the consolidated balance sheets due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company defers the recognition of the respective adjustments and recognizes the adjustments in non-controlling interest on the consolidated statements of operations on a straight-line basis over the expected life of the underlying assets giving rise to the respective difference. Similarly, where the Company has acquired a controlling interest in a partnership and there is a resulting difference between the initial fair value of non-controlling interest and the value of non-controlling interest as measured using HLBV, the Company initially records non-controlling interests at fair value and amortizes the resulting difference over the remaining life of the underlying assets.

Contingencies

The Company is involved in conditions, situations or circumstances in the ordinary course of business with possible gain or loss contingencies that will ultimately be resolved when one or more future events occur or fail to occur. If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, that amount will be accrued. When no amount within the range is a better estimate than any other amount, the minimum amount in the range will be accrued. The Company continually evaluates uncertainties associated with loss contingencies and records a charge equal to at least the minimum estimated liability for a loss contingency when both of the following conditions are met: (i) information available prior to the issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements; and (ii) the loss or range of loss can be reasonably estimated. Legal costs are expensed when incurred. Gain contingencies are not recorded until realized or realizable.

Derivative Financial Instruments

Adoption of ASU 2017-12

On January 1, 2018, the Company adopted ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities which primarily resulted in simplification of the assessment of hedge

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effectiveness for derivatives designated in a qualifying cash flow relationship, and the periodic recognition of gains and losses related to certain components of AOCI. The Company adopted ASU No. 2017-12 using the modified retrospective transition method resulting in a cumulative-effect adjustment of $4.2 million, net of tax of $1.6 million, representing a decrease in accumulated deficit and AOCI, which is reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018.

Initial Recognition

The Company recognizes its derivative instruments as assets or liabilities at fair value in the consolidated balance sheets on a trade date basis unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated as part of a hedging relationship and the type of hedging relationship.

Derivatives that qualify and are designated for hedge accounting are classified as either hedges of the variability of expected future cash flows to be received or paid related to a recognized asset or liability (cash flow hedges) or hedges of the exposure to foreign currency of a net investment in a foreign operation (net investment hedges).

The Company also uses derivative contracts outside the hedging program to manage foreign currency risk associated with intercompany loans.

Subsequent Measurement

The change in fair value of components included in the effectiveness assessment of derivative instruments designated as cash flow hedges is recognized as a component of OCI and reclassified into earnings on a trade date basis in the period that the hedged transaction affects earnings. The change in fair value of components included in the effectiveness assessment of foreign currency contracts designated as net investment hedges is recorded in cumulative translation adjustments within AOCI and reclassified into earnings when the foreign operation is sold or substantially liquidated.

The change in fair value of derivative contracts intended to serve as economic hedges that are not designated as hedging instruments is reported as a component of earnings in the consolidated statements of operations.

Cash flows from derivative instruments designated as net investment hedges and non-designated derivatives used to manage foreign currency risks associated with intercompany loans are classified as investing activities in the

consolidated statements of cash flows. Cash flows from all other derivative instruments are classified as operating activities in the consolidated statements of cash flows.

Fair Value Measurements

The Company performs fair value measurements defined as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required to be recorded at their fair values, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer restrictions and risk of nonperformance.

In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:

•Level 1: Quoted prices in active markets for identical assets or liabilities;

•Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; or

•Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair values of the assets or liabilities.

The Company maintains various financial instruments recorded at cost in the consolidated balance sheets that are not required to be recorded at fair value. For cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and other current assets, accounts payable and accrued expenses and other current liabilities and due to affiliates, net, the carrying

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amount approximates fair value because of the short-term maturity of the instruments. See Note 13. Fair Value of Financial Instruments for disclosures related to the fair value of the Company’s derivative instruments and long-term debt.

Foreign Currency

The Company’s reporting currency is the U.S. dollar. Certain of the Company’s subsidiaries maintain their records in local currencies other than the U.S. dollar, which are their functional currencies. When a subsidiary’s local currency is considered its functional currency, the Company translates its assets and liabilities to U.S. dollars using exchange rates in effect at date of the financial statements and its revenue and expense accounts to U.S. dollars at average exchange rates for the period. Cumulative translation adjustments are reported in AOCI in stockholders’ equity. Cumulative translation adjustments are reclassified from AOCI to earnings only when realized upon sale or upon complete or substantially complete liquidation of an investment in a foreign subsidiary. Transaction gains and losses and changes in fair value of the Company’s foreign exchange derivative contracts not accounted for under hedge accounting are included in results of operations as recognized.

Business Combinations and Acquisitions of Assets

The Company applies the definition of a business in ASC 805, Business Combinations to determine whether it is acquiring a business or a group of assets.

The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, acquisition costs related to business combinations are expensed as incurred.

When the Company acquires a renewable energy business, the purchase price is allocated to (i) the acquired tangible assets and liabilities assumed, primarily consisting of land, plant and long-term debt, (ii) the identified intangible assets and liabilities, primarily consisting of the value of favorable and unfavorable rate PPAs, REC agreements, the licensing contracts and in-place value of market rate PPAs, (iii) non-controlling interests, and (iv) other working capital items based in each case on their fair values. The excess of the purchase price over the estimated fair value of net assets acquired is recorded as goodwill.

The Company generally uses independent appraisers to assist with the estimates and methodologies used such as a replacement cost approach, or an income approach or excess earnings approach. Factors considered by the Company in its analysis include considering current market conditions and costs to construct similar facilities. The Company also considers information obtained about each facility as a result of its pre-acquisition due diligence in estimating the fair value of the tangible and intangible assets and liabilities acquired or assumed. In estimating the fair value, the Company also establishes estimates of energy production, current in-place and market power purchase rates, tax credit arrangements and operating and maintenance costs. A change in any of the assumptions above, which are subjective, could have a significant impact on the results of operations.

The allocation of the purchase price directly affects the following items in the consolidated financial statements:

•The amount of purchase price allocated to the various tangible and intangible assets, liabilities and non-controlling interests on the balance sheet;

•The amounts allocated to the value of favorable and unfavorable rate PPAs and REC agreements are amortized to revenue over the remaining non-cancelable terms of the respective arrangement. The amounts allocated to all other tangible assets and intangibles are amortized to depreciation or amortization expense; and

•The period of time over which tangible and definite-lived intangible assets and liabilities are depreciated or amortized varies, and thus, changes in the amounts allocated to these assets and liabilities will have a direct impact on the Company’s results of operations.

ASC 805 allows the acquirer to report provisional amounts and adjust them for a period of time up to one year after the acquisition date (the “measurement period”) while the Company obtains information about the facts and circumstances that existed as of the acquisition date.

When an acquired group of assets does not constitute a business, the transaction is accounted for as an asset acquisition. The Company recognizes and measures the acquired assets based on the cost of the acquisitions, generally being the consideration transferred to the seller and typically includes the direct transaction costs related to the acquisition. The

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Company allocates the total cost of acquisition to the individual assets acquired or liabilities assumed based on their relative fair values generally similar to the allocation of the purchase price in a business combination. No goodwill is recognized in an asset acquisition.

Assets Held for Sale

The Company records assets held for sale at the lower of the carrying value or fair value less costs to sell. The following criteria are used to determine if property is held for sale: (i) management has the authority and commits to a plan to sell the property; (ii) the property is available for immediate sale in its present condition; (iii) there is an active program to locate a buyer and the plan to sell the property has been initiated; (iv) the sale of the property is probable within one year; (v) the property is being actively marketed at a reasonable price relative to its current fair value; and (vi) it is unlikely that the plan to sell will be withdrawn or that significant changes to the plan will be made.

In determining the fair value of the assets less costs to sell, the Company considers factors including current sales prices for comparable assets in the region, recent market analysis studies, appraisals and any recent legitimate offers. If the estimated fair value less costs to sell of an asset is less than its current carrying value, the asset is written down to its estimated fair value less costs to sell. Due to uncertainties in the estimation process, it is reasonably possible that actual results could differ from the estimates used in the Company’s historical analysis. The Company’s assumptions about project sale prices require significant judgment because the current market is highly sensitive to changes in economic conditions. The Company estimates the fair values of assets held for sale based on current market conditions and assumptions made by management, which may differ from actual results and may result in additional impairments if market conditions deteriorate.

When assets are classified as held for sale, the Company does not record depreciation or amortization for the respective renewable energy facilities or intangibles.

At December 31, 2019 and 2018, there were no assets held for sale.

Stock-Based Compensation

Stock-based compensation expense for all share-based payment awards to certain employees who provide services to the Company is based on the estimated grant-date fair value. The Company recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award vesting term. For ratable awards, the Company recognizes compensation costs for all grants on a straight-line basis over the requisite service period of the entire award. The Company recognizes the effect of forfeitures in compensation costs when they occur.

Deferred Compensation Plan

The Company sponsors a retirement saving plan that qualifies as a deferred compensation plan under Section 401(k) of the Internal Revenue Code. Eligible U.S. employees may elect to defer a percentage of their qualified compensation for income tax purposes through payroll deductions, and the Company matches a percentage of the contributions based on employees’ elective deferrals. The Company’s total matching contribution expense under the arrangement was $0.5 million, $0.6 million and $0.5 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Restructuring

The Company accounts for restructuring costs in accordance with ASC 712 and ASC 420, as applicable. In connection with the consummation of the Merger and the relocation of the Company’s headquarters to New York, New York, the Company announced a restructuring plan that went into effect upon the closing of the Merger. The Company recognized $0.1 million and $3.7 million of severance and transition bonus costs related to this restructuring within general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2019, and 2018. Severance and transition bonus payments were $0.4 million and $5.5 million during the years ended December 31, 2019, and 2018.

Recently Adopted Accounting Standards - Additional Guidance Adopted in 2019

In October 2018, the FASB issued ASU No. 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (“SOFR”) Overnight Index Swap (“OIS”) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes. This ASU expands the list of United States (“U.S.”) benchmark interest rates permitted in the application of hedge accounting by adding the SOFR as a permissible U.S. benchmark rate. The Company does not have any derivative instruments

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indexed to SOFR as a benchmark interest rate, accordingly, the adoption of ASU No. 2018-16 as of January 1, 2019 did not have an impact on the Company’s consolidated financial statements.

Recently Issued Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), to provide financial statement users with more useful information about the current expected credit losses (“CECL”). This ASU changes how entities measure credit losses on financial instruments and the timing of when such losses are recognized by utilizing a lifetime expected credit loss measurement. The guidance is effective for fiscal years and interim periods within those years beginning after January 1, 2020. The Company does not expect the adoption of Topic 326 to have a material impact on its results of operations.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement. This ASU removes some disclosure requirements, modifies others, and adds some new disclosure requirements. The guidance is effective January 1, 2020, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40) Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. This ASU amends the definition of a hosting arrangement and requires a customer in a cloud computing arrangement that is a service contract to follow the internal use software guidance in ASC 350-402 to determine which implementation costs to capitalize as assets. Capitalized implementation costs are amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. The guidance is effective January 1, 2020, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In October 2018, the FASB issued ASU No. 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities. The amendments in this ASU require reporting entities to consider indirect interests held through related parties under common control for determining whether fees paid to decision makers and service provider are variable interests. These indirect interests should be considered on a proportional basis rather than as the equivalent of a direct interest in its entirety (as currently required in U.S. GAAP). The guidance is effective January 1, 2020, with early adoption permitted. Entities are required to apply the amendments in this guidance retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this ASU simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740, Income Taxes. The amendments also improve consistent application or and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The guidance is effective January 1, 2021, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

3. ACQUISITIONS AND DIVESTITURES

2019 Acquisitions

(i) WGL Acquisition

On September 26, 2019, TerraForm Arcadia Holdings, LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Company (“TerraForm Arcadia”), completed the acquisition of an approximately 320 MW distributed generation portfolio of renewable energy facilities in the United States from subsidiaries of AltaGas Ltd., a Canadian corporation (“AltaGas”), for a purchase price of $720.0 million, plus $15.1 million for working capital. The acquisition was pursuant to a membership interest purchase agreement (the “Purchase Agreement”) dated July 19, 2019, entered into by TerraForm Arcadia, WGL Energy Systems, Inc., a Delaware corporation (“WGL”), and WGSW, Inc., a Delaware corporation (“WGSW”, and together with WGL, the “Sellers”), both subsidiaries of AltaGas (the “WGL Acquisition”). Pursuant to the Purchase Agreement, the ownership of certain projects for which the Sellers had not yet received the required third party consents or had not completed construction as of the closing date (the “Delayed Projects”) were to be transferred to the Company once such third party consents were received or construction was completed, subject to certain terms and conditions. The Delayed Projects represented 11.6 MW of the combined nameplate capacity of the acquired renewable energy facilities as

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of December 31, 2019. The purchase price allocated to the Delayed Projects based on the Purchase Agreement was $24.8 million, and is presented as Deposit on acquisitions on the consolidated balance sheets. In the event that the title to certain Delayed Projects is not transferred to the Company within a certain period of time, the Company is entitled to a full refund of the value of these projects based on the Purchase Agreement.

The Company funded the purchase price and the related initial costs of the WGL Acquisition with the net proceeds of $475.0 million Bridge Facility and the remainder from draws on the Revolver. See Note 10. Long-term Debt for additional details.

The Company accounted for the WGL Acquisition under the acquisition method of accounting for business combinations. The final accounting has not been completed since the evaluation necessary to assess the fair values of acquired assets and assumed liabilities is still in process. The additional information needed by the Company to finalize the measurement of these provisional amounts include, but not limited to, additional information regarding certain energy markets in the United States, the estimation of the removal costs for the acquired assets, the completion of the transfer of the Delayed Projects, and the assessment of the incremental borrowing rate for operating leases. The provisional amounts for this business combination are subject to revision until these evaluations are completed.

The preliminary allocation of the acquisition-date fair values of assets, liabilities and non-controlling interests pertaining to this business combination as of December 31, 2019, were as follows:

(In thousands)	As of September 26, 2019
Renewable energy facilities in service1	$	581,717
Intangible assets	168,825
Accounts receivable	13,160
Prepaid expenses and other assets	9,734
Total assets acquired	773,436
Accounts payable, accrued expenses and other current liabilities	6,806
Asset retirement obligations	27,338
Operating lease liabilities	21,663
Other liabilities	7,650
Total liabilities assumed	63,457
Non-controlling interests2	3,028
Purchase price, net of cash and restricted cash acquired3	706,951
Deposit on acquisitions	24,831
Total cash paid for the WGL Acquisition, net of cash acquired3	$	731,782

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(1)Includes $22.6 million operating lease right-of-use assets.

(2)The fair value of the non-controlling interests was determined using an income approach representing the best indicator of fair value and was supported by a discounted cash flow technique.

(3)The Company acquired cash and cash equivalents of $3.4 million as of the acquisition date.

The acquired non-financial assets primarily represent an estimate of the fair value of the acquired renewable energy facilities and intangible assets from PPAs using the cost and income approach. Key inputs used to estimate fair value included forecasted power pricing, operational data, asset useful lives and a discount rate factor reflecting current market conditions at the time of the acquisition. These significant inputs are not observable in the market and thus represent Level 3 measurements, as defined in Note 13. Fair Value of Financial Instruments. Refer below for additional disclosures related to the acquired finite-lived intangible assets.

The results of operations from the acquired entities are included in the Company’s consolidated results since the date of acquisition. The operating revenues and net income related to the WGL Acquisition reflected in the consolidated statements of operations for the year ended December 31, 2019, were $13.8 million and $0.1 million, respectively.

Intangibles at Acquisition Date

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The Company attributed the intangible asset values to favorable rate revenue contracts and PPAs in-place from renewable energy facilities and the intangible liabilities to unfavorable rate revenue contracts. The following table summarizes the estimated fair values and the weighted average amortization periods of the acquired intangible assets and assumed intangible liabilities as of the acquisition date:

	WGL Acquisition
	Fair Value (In thousands)		Weighted Average Amortization Period
Favorable rate revenue contracts	$	27,400	16 years
In-place value of market rate revenue contracts	141,425		15 years
Unfavorable rate revenue contracts	7,650		2 years

———

(1)For the purposes of this disclosure, the weighted average amortization periods are determined based on a weighting of the individual intangible fair values against the total fair value for each major intangible asset class.

Unaudited Pro Forma Supplementary Data

The unaudited pro forma supplementary data presented in the table below gives effect to the WGL Acquisition, as if the transaction had occurred on January 1, 2018. The pro forma net loss includes interest expense related to incremental borrowings used to finance the transaction and adjustments to depreciation, accretion and amortization expense for the valuation of renewable energy facilities, intangible assets, and asset retirement obligations, and excludes the impact of acquisition costs disclosed below. The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed to be indicative of the Company’s results of operations had the acquisition been consummated on the date assumed or of the Company’s consolidated results of operations for any future date.

	Year Ended December 31,
(In thousands)	2019		2018
Total operating revenues, net	$	1,011,526	$	831,145
Net loss	(214,280)		(185,392)

(ii) X-Elio Acquisition

On December 18, 2019, Cuanto De Luz, S.L.U., a wholly-owned subsidiary of the Company, completed the acquisition of approximately 45 MW utility-scale solar photovoltaic power facilities in Spain, from subsidiaries of X-Elio Energy, S.L., a Spanish corporation (the “X-Elio Acquisition”), for a total purchase price of €63.8 million (equivalent to $71.1 million at the date of the acquisition). The Company funded the acquisition with a portion of the net proceeds of the utility-scale wind non-recourse borrowing refinancing and cash available on hand. See Note 10. Long-term Debt for additional details. These facilities are regulated under the Spanish framework for renewable power, with approximately 21 years of remaining regulatory life. This transaction was accounted for as an acquisition of assets, whereby the Company acquired approximately $186.5 million renewable energy facilities, and $54.8 million intangible assets attributable to licensing contracts in-place from the acquired solar facilities using the cost and income approach.

(iii) Acquisition of 15.1 MW Distributed Generation Assets

During the year ended December 31, 2019, the Company acquired four distributed generation facilities located in the U.S. with a combined nameplate capacity of 15.1 MW from third parties for a total purchase price of $24.0 million plus working capital adjustments. The facilities are contracted under long-term PPAs with municipal offtakers. This transaction was accounted for as an acquisition of assets.

2018 Acquisitions

(i) Saeta Acquisition

On February 7, 2018, the Company announced that it intended to launch a voluntary tender offer (the “Tender Offer”) to acquire 100% of the outstanding shares of Saeta, a Spanish renewable power company with then over 1,000 MW of solar and wind facilities (approximately 250 MW of solar and 778 MW of wind) located primarily in Spain. The Tender Offer was for €12.20 in cash per share of Saeta. On June 8, 2018, the Company announced that Spain’s National Securities Market

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Commission confirmed an over 95% acceptance of shares of Saeta in the Tender Offer (the “Tendered Shares”). On June 12, 2018, the Company completed the acquisition of the Tendered Shares for total aggregate consideration of $1.12 billion and the assumption of $1.91 billion of project-level debt. Having acquired 95.28% of the shares of Saeta, the Company then pursued a statutory squeeze out procedure under Spanish law to procure the remaining approximately 4.72% of the shares of Saeta for $54.6 million.

The Company funded the $1.12 billion purchase price of the Tendered Shares with $650.0 million of proceeds from the private placement of its Common Stock to Orion Holdings and BBHC Orion Holdco L.P. as discussed in Note 16. Stockholders’ Equity, along with approximately $471 million from its existing liquidity, including (i) the proceeds of a $30.0 million draw on its Sponsor Line (as defined in Note 10. Long-term Debt), (ii) a $359.0 million as part of a draw on the Company’s Revolver (as defined in Note 10. Long-term Debt), and (iii) approximately $82 million of cash on hand. The Company funded the purchase of the remaining approximately 4.72% non-controlling interest in Saeta using $54.6 million of the total proceeds from an additional draw on its Sponsor Line.

The Company accounted for the acquisition of Saeta under the acquisition method of accounting for business combinations. The purchase accounting for the Saeta acquisition, including assignment of goodwill to reporting units, was finalized as of June 30, 2019. The final allocation of the acquisition-date fair values of assets, liabilities and redeemable non-controlling interests pertaining to this business combination as of December 31, 2019, was as follows:

(In thousands)	As of June 12, 2018, reported at December 31, 2018		Adjustments		As of June 12, 2019, reported at December 31, 2019
Renewable energy facilities in service	$	1,993,520	$	252,071	$	2,245,591
Accounts receivable	91,343		—		91,343
Intangible assets	1,034,176		(290,171)		744,005
Goodwill1	123,106		10,195		133,301
Other assets	43,402		2,845		46,247
Total assets acquired	3,285,547		(25,060)		3,260,487
Accounts payable, accrued expenses and other current liabilities	93,032		(1,761)		91,271
Long-term debt, including current portion	1,906,831		(12,405)		1,894,426
Deferred income taxes	171,373		(10,800)		160,573
Asset retirement obligations	67,706		(94)		67,612
Derivative liabilities	137,002		—		137,002
Other long-term liabilities	23,002		—		23,002
Total liabilities assumed	2,398,946		(25,060)		2,373,886
Redeemable non-controlling interests2	55,117		—		55,117
Purchase price, net of cash acquired3	$	831,484	$	—	$	831,484

———

(1)The excess purchase price over the estimated fair value of net assets acquired of $133.3 million was recorded as goodwill, with $103.8 million assigned to the Regulated Solar and Wind segment and $29.5 million assigned to the Wind segment. See Note 7. Intangible Assets, Net and Goodwill and Note 23. Segment Reporting for additional details.

(2) The fair value of the non-controlling interests was determined using a market approach using a quoted price for the instrument. As discussed above, the Company acquired the remaining shares of Saeta pursuant to a statutory squeeze out procedure under Spanish law, which closed on July 2, 2018. The quoted price for the purchase of the non-controlling interest was the best indicator of fair value and was supported by a discounted cash flow technique.

(3)The Company acquired cash and cash equivalents of $187.2 million and restricted cash of $95.1 million as of the acquisition date.

The acquired non-financial assets primarily represent estimates of the fair value of acquired renewable energy facilities and intangible assets from licensing agreements using the cost and income approach. Key inputs used to estimate fair value included forecasted power pricing, operational data, asset useful lives, and a discount rate factor reflecting current market conditions at the time of the acquisition. These significant inputs are not observable in the market and thus represent Level 3 measurements (as defined in Note 13. Fair Value of Financial Instruments). Refer below for additional disclosures related to the acquired finite-lived intangible assets.

The results of operations of Saeta are included in the Company’s consolidated results since the date of acquisition for the year ended December 31, 2018, and for the entire year ended December 31, 2019. The operating revenues and net income

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of Saeta reflected in the consolidated statements of operations for the year ended December 31, 2019 were $407.1 million and $57.6 million, respectively, and $221.2 million and $38.2 million for the year ended December 31, 2018, respectively.

Intangibles at Acquisition Date

The Company attributed intangible asset value to licensing contracts in-place from solar and wind facilities. These intangible assets are amortized on a straight-line basis over the estimated remaining useful life of the facility from the Company’s acquisition date. The following table summarizes the estimated fair value and weighted average amortization period of acquired intangible assets as of the acquisition date for Saeta:

	Saeta as of June 12, 2018
	Fair Value (In thousands)		Weighted Average Amortization Period (In years)1
Intangible assets - licensing contracts	$	744,005	14 years

———

(1)For purposes of this disclosure, the weighted average amortization period is determined based on a weighting of the individual intangible fair values against the total fair value for each major intangible asset and liability class.

Out-of-Period Adjustments

During the preparation of the Company’s consolidated financial statements for the year ended December 31, 2019, management discovered errors related to the Saeta business combination as included in the Company’s consolidated condensed financial statements for the year ended December 31, 2018, included in the previously filed Annual Report on Form 10-K for the related period, and the unaudited consolidated condensed financial statements for the periods ended March 31, 2019, June 30, 2019, and September 30, 2019, as included in the previously filed Quarterly Reports on Form 10-Q for the related periods. Specifically, the Company allocated the entire value of $258.3 million of acquired projects within the International Wind operating segment as intangible assets without an allocation to renewable energy facilities. Additionally, the Company overstated the estimated fair value of assumed non-recourse long-term project debt as of June 30, 2019, and September 30, 2019, by approximately $28.5 million. The correction of these errors resulted in a $258.3 million increase in renewable energy facilities, net, a $258.3 million decrease in intangible assets, a $28.5 million decrease in long-term debt, a $22.0 million decrease in goodwill, and a $6.5 million increase in deferred tax liabilities. The correction did not have a material impact on the previously reported amounts of net loss, and comprehensive loss, and did not have any impact on the previously reported consolidated cash flows from operating, investing, or financing activities.

The Company evaluated the errors and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company’s consolidated financial statements for any prior period. Therefore, amendments to the previously filed reports were not required.

Unaudited Pro Forma Supplementary Data

The unaudited pro forma supplementary data presented in the table below shows the effect of the Saeta acquisition, as if the transaction had occurred on January 1, 2017. The pro forma net loss includes interest expense related to incremental borrowings used to finance the transaction and adjustments to depreciation and amortization expense for the valuation of renewable energy facilities and intangible assets. The pro forma net loss for the year ended December 31, 2019, excludes the impact of acquisition related costs disclosed below. The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed to be indicative of the Company’s results of operations had the acquisition been consummated on the date assumed or of the Company’s results of operations for any future date.

(In thousands)	Year Ended December 31, 2018
Total operating revenues, net	$	950,992
Net loss	(143,903)

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(ii) Acquisition of 6.1 MW Distributed Generation Portfolio

In 2018, the Company acquired six distributed generation facilities located in the U.S. with a combined nameplate capacity of 6.1 MW from third parties for a purchase price of $4.1 million, net of cash acquired. The facilities are contracted under long-term PPAs with municipal offtakers. This transaction was accounted for as an acquisition of assets.

Acquisition Costs

Total Acquisition costs incurred by the Company for the year ended December 31, 2019, were $4.7 million. Costs related to affiliates included in these balances were $0.9 million. Acquisition costs incurred by the Company for the year ended December 31, 2018 were $14.6 million. Costs related to affiliates included in these balances were $6.9 million. These costs are reflected as acquisition costs and acquisition costs - affiliate (see Note 21. Related Parties) in the consolidated statements of operations and are excluded from the unaudited pro forma net loss amount disclosed above.

2019 Divestiture

(i) Sale of Six Distributed Generation Facilities in the United States

On December 20, 2019, the Company sold six distributed generation facilities in the United States, with a combined nameplate capacity of 6.0 MW, for a net consideration of $9.5 million. The Company recognized a net gain of $2.3 million representing the difference between the net proceeds from the sale and the net carrying amount of assets sold and liabilities extinguished, was recorded in the consolidated statement of operations for the year ended December 31, 2019 within the gain on sale of renewable energy facilities.

2017 Divestitures

(i) U.K. Portfolio Sale

On May 11, 2017, the Company announced that it completed its sale of substantially all of its portfolio of solar power plants located in the United Kingdom (24 operating projects representing an aggregate 365.0 MW, the “U.K. Portfolio”) to Vortex Solar UK Limited, a renewable energy platform managed by the private equity arm of EFG Hermes, an investment bank. The Company received approximately $214.1 million of proceeds from the sale, which was net of transaction expenses of $3.9 million and distributions taken from the U.K. Portfolio after announcement and before closing of the sale. The Company also disposed of $14.8 million of cash and cash equivalents and $21.8 million of restricted cash as a result of the sale. The proceeds were used for the reduction of the Company’s indebtedness (a $30.0 million prepayment for a non-recourse portfolio term loan and the remainder was applied towards revolving loans outstanding under its senior secured corporate-level revolving credit facility). The sale also resulted in a reduction in the Company’s non-recourse project debt by approximately £301 million British pounds sterling at the U.K. Portfolio level. The Company recognized a gain on the sale of $37.1 million, which is reflected within Gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017. The Company retained one 11.1 MW solar project in the United Kingdom.

(ii) Residential Portfolio Sale

In 2017, the Company closed on the sale of 100% of the membership interests of Enfinity Colorado DHA 1, LLC, a Colorado limited liability company that owned and operated 2.5 MW of solar installations situated on the roof of public housing units located in Colorado and owned by the Denver Housing Authority, and 100% of the membership interests of TerraForm Resi Solar Manager, LLC, a subsidiary of the Company that owned and operated 8.9 MW of rooftop solar installations, to Greenbacker Residential Solar II, LLC. The Company received proceeds of $7.1 million during 2017 as a result of the sale of these companies and also disposed of $0.6 million of cash and cash equivalents and $0.8 million of restricted cash. There was no additional loss recognized during 2017 as a result of these sales.

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4. REVENUE

The following table presents the Company’s operating revenues, net and disaggregated by revenue source:

	Year Ended December 31, 2019								Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Total		Solar		Wind		Regulated Solar and Wind		Total
PPA rental income	$	199,266	$	191,508	$	—	$	390,774	$	198,610	$	192,324	$	—	$	390,934
Commodity derivatives	—		37,054		—		37,054		—		46,287		—		46,287
PPA and market energy revenue	46,740		79,253		97,953		223,946		39,566		54,998		58,742		153,306
Capacity revenue from remuneration programs1	—		—		204,991		204,991		—		—		108,242		108,242
Amortization of favorable and unfavorable rate revenue contracts, net	(8,850)		(31,090)		—		(39,940)		(9,743)		(29,024)		—		(38,767)
Energy revenue	237,156		276,725		302,944		816,825		228,433		264,585		166,984		660,002
Incentive revenue2	79,277		9,414		35,724		124,415		70,533		16,364		19,671		106,568
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	941,240	$	298,966	$	280,949	$	186,655	$	766,570

———

(1)Represents the return related to the Company’s investments associated with its renewable energy facilities in Spain. See Note 2. Summary of Significant Accounting Policies for additional details.

(2)Incentive revenue earned at the Regulated Solar and Wind segment represents the return per MWh generated by the Company’s solar facilities in Spain to recover certain operating expenses. See Note 2. Summary of Significant Accounting Policies for additional details.

Contract balances and performance obligations

The Company recognizes accounts receivable when its right to consideration from the performance of services becomes unconditional. The Company establishes an allowance for doubtful accounts to adjust its receivables to amounts considered to be ultimately collectible and charges to the allowance are recorded within general and administrative expenses in the consolidated statements of operations. The Company’s allowance is based on a variety of factors, including the length of time receivables are past due, significant one-time events, the financial health of its customers and historical experience. As of December 31, 2019 and 2018, the Company’s receivable balances related to PPA contracts with solar and wind customers were approximately $104.1 million and $83.5 million, respectively. Trade receivables for PPA contracts are reflected within accounts receivable, net in the consolidated balance sheets. The Company typically receives payment within 30 days for invoiced PPA revenue.

Energy revenues yet to be earned under these contracts are expected to be recognized between 2020 and 2043. The Company applies the practical expedient in Topic 606 to its bundled PPA contract arrangements, and accordingly, does not disclose the value of unsatisfied performance obligations for contracts for which it recognizes revenue at the amount to which it has the right to invoice for services performed.

As of December 31, 2019 and December 31, 2018, other liabilities in the consolidated balance sheets included deferred revenue comprising of $8.4 million and $8.8 million upfront government incentives, respectively, and $1.8 million and $4.9 million contract liabilities related to performance obligations that have not yet been satisfied, respectively. These contract liabilities represented advanced customer receipts primarily related to future REC deliveries that are recognized into revenue under Topic 606. The amount of revenue recognized during the year ended December 31, 2019 and 2018, related to contract liabilities was $3.1 million and $1.3 million, respectively.

5. CASH AND CASH EQUIVALENTS

Cash and cash equivalents include all cash balances and money market funds, including restricted cash, with original maturity periods of three months or less when purchased. As of December 31, 2019 and December 31, 2018, cash and cash equivalents included $138.5 million and $177.6 million, respectively, of unrestricted cash held at project-level subsidiaries, which was available for project expenses but not available for corporate use.

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Reconciliation of Cash and Cash Equivalents and Restricted Cash as Presented in the Consolidated Statements of Cash Flows

The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the consolidated balance sheets to the total of the same such amounts shown in the consolidated statements of cash flows for the years ended December 31, 2019, 2018 and 2017:

	As of December 31,
(In thousands)	2019		2018		2017
Cash and cash equivalents	$	237,480	$	248,524	$	128,087
Restricted cash, current	35,657		27,784		54,006
Restricted cash - non-current	76,363		116,501		42,694
Cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows	$	349,500	$	392,809	$	224,787

As discussed in Note 10. Long-term Debt, the Company was in default under certain of its non-recourse financing agreements as of the financial statement issuance date for the years ended December 31, 2019 and 2018. As a result, the Company reclassified $11.0 million and $11.2 million, respectively, of long-term restricted cash to current as of December 31, 2019, and 2018, consistent with the corresponding debt classification, as the restrictions that required the cash balances to be classified as long-term restricted cash were driven by the financing agreements.

6. RENEWABLE ENERGY FACILITIES

Renewable energy facilities, net consists of the following: 

	As of December 31,
(In thousands)	2019		2018
Renewable energy facilities in service, at cost1	$	8,584,243	$	7,298,371
Less accumulated depreciation - renewable energy facilities	(1,191,056)		(833,844)
Renewable energy facilities in service, net	7,393,187		6,464,527
Construction in progress - renewable energy facilities	12,274		5,499
Total renewable energy facilities, net	$	7,405,461	$	6,470,026

———

(1)As discussed in Note 2. Summary of Significant Accounting Policies and Note 8. Leases, on January 1, 2019, the Company recognized $262.1 million right-of-use of assets related to operating leases as a result of the adoption of Topic 842, which is included within renewable energy facilities. The amount of right-of-use of assets as of December 31, 2019 was $288.3 million.

Depreciation expense related to renewable energy facilities was $325.1 million, $270.4 million and $212.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Sale of Assets

On December 20, 2019, the Company sold six distributed generation facilities in the United States, with a combined nameplate capacity of 6.0 MW, for a net consideration of $9.5 million. The Company recognized a net gain of $2.3 million, representing the difference between the net proceeds from the sale and the net carrying amount of assets sold and liabilities extinguished, in the consolidated statement of operations for the year ended December 31, 2019, within Gain on sale of renewable energy facilities.

Impairment Assessment

During the year ended December 31, 2019, the Company identified opportunities to repower two wind power plants in the Northeast with a combined nameplate capacity of 160 MW by replacing certain components of the wind turbines with newer equipment while preserving the existing towers, foundation and balance of plant. The Company views repowering activities as opportunities to increase efficiency and extend the useful lives of existing renewable energy facilities. The Company performed impairment testing for these two wind power plants and did not record any impairment losses since it was

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determined that the expected undiscounted cash flows were greater than the net carrying amount of the related renewable energy facilities of $79.4 million as of December 31, 2019. If the Company determines to move forward with the repowering activities for one or both of these wind plants during the year 2020, the Company will revise the estimated remaining useful lives of certain components of the renewable energy facilities that will be replaced in the repowering activities and accelerate the recognition of depreciation expense to no later than the removal date.

The Company had a REC sales agreement expiring on December 31, 2021, with a customer within a distributed generation portfolio, and on March 31, 2018, the customer filed for protection under Chapter 11 of the U.S. Bankruptcy Code. The potential replacement of this contract would likely result in a significant decrease in expected revenues for this operating project. The Company’s analysis indicated that the bankruptcy filing was a triggering event to perform an impairment evaluation, and the carrying amount of $19.5 million as of March 31, 2018 was no longer considered recoverable based on an undiscounted cash flow forecast. The Company estimated the fair value of the operating project at $4.3 million as of March 31, 2018 and recognized an impairment charge of $15.2 million equal to the difference between the carrying amount and the estimated fair value, which is reflected within impairment of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2018. The Company used an income approach methodology of valuation to determine fair value by applying a discounted cash flow method to the forecasted cash flows of the operating project, which was categorized as a Level 3 fair value measurement due to the significance of unobservable inputs. Key estimates used in the income approach included forecasted power and incentive prices, customer renewal rates, operating and maintenance costs and the discount rate.

The Company sold 0.3 MW of residential assets (that were not classified as held for sale as of December 31, 2016) during the third quarter of 2017. These assets did not meet the criteria for held for sale classification as of June 30, 2017 but the Company determined that certain impairment indicators were present and as a result recognized an impairment charge of $1.4 million within impairment of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

No impairment losses were recognized for the twelve months ended December 31, 2019.

7. INTANGIBLE ASSETS, NET AND GOODWILL

The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2019:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization		Net Book Value
Licensing agreements	13 years	$	765,451	$	(81,647)	$	683,804
Favorable rate revenue contracts	12 years	745,784		(195,287)		550,497
In-place value of market rate revenue contracts	16 years	688,832		(129,841)		558,991
Total intangible assets, net		$	2,200,067	$	(406,775)	$	1,793,292
Unfavorable rate revenue contracts	8 years	$	48,420	$	(32,556)	$	15,864
Total intangible liabilities, net1		$	48,420	$	(32,556)	$	15,864

———

(1)The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

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The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2018:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization		Net Book Value
Licensing contracts1	15 years	$	1,015,824	$	(36,374)	$	979,450
Favorable rate revenue contracts	14 years	738,488		(166,507)		571,981
In-place value of market rate revenue contracts	18 years	532,844		(100,543)		432,301
Favorable rate land leases2	16 years	15,800		(3,128)		12,672
Total intangible assets, net		$	2,302,956	$	(306,552)	$	1,996,404
Unfavorable rate revenue contracts	6 years	$	58,508	$	(41,605)	$	16,903
Unfavorable rate operations and maintenance contracts	1 year	5,000		(3,802)		1,198
Unfavorable rate land lease2	14 years	1,000		(218)		782
Total intangible assets, net3		$	64,508	$	(45,625)	$	18,883

———

(1)Represents the intangible assets recognized under the Saeta acquisition and attributed to licensing contracts in-place from the acquired solar and wind facilities. See Note 3. Acquisitions and Divestitures for additional details.

(2)On January 1, 2019, these amounts were reclassified to right-of-use assets in connection with the adoption of Topic 842. See Note 2. Summary of Significant Accounting Policies and Note 8. Leases for additional details.

(3)The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

Amortization expense related to the licensing contracts acquired from Saeta is reflected in the consolidated statements of operations within depreciation, accretion and amortization expense. During the years ended December 31, 2019 and 2018, amortization expense related to the licensing contracts was $66.9 million and $36.4 million, respectively.

Amortization expense related to favorable rate revenue contracts is reflected in the consolidated statements of operations as a reduction of operating revenues, net. Amortization related to unfavorable rate revenue contracts is reflected in the consolidated statements of operations as an increase to operating revenues, net. During the years ended December 31, 2019, 2018 and 2017, net amortization expense related to favorable and unfavorable rate revenue contracts resulted in a reduction of operating revenues, net of $39.9 million, $38.8 million and $39.6 million, respectively.

Amortization expense related to the in-place value of market rate revenue contracts is reflected in the consolidated statements of operations within depreciation, accretion and amortization expense. During the years ended December 31, 2019, 2018 and 2017, amortization expense related to the in-place value of market rate revenue contracts was $26.2 million, $28.2 million, and $25.5 million, respectively.

Over the next five years, the Company expects to recognize annual amortization on its intangibles as follows:

(In thousands)	2020		2021		2022		2023		2024
Favorable rate revenue contracts	$	47,555	$	44,789	$	43,598	$	43,598	$	43,598
Unfavorable rate revenue contracts	(7,545)		(2,710)		(1,628)		(1,007)		(279)
Total net amortization expense recorded to operating revenues, net	$	40,010	$	42,079	$	41,970	$	42,591	$	43,319
Licensing contracts	$	57,152	$	57,152	$	57,152	$	57,152	$	57,152
In-place value of market rate revenue contracts	38,517		38,517		38,517		38,510		38,503
Total amortization expense recorded to depreciation, accretion and amortization expense	$	95,669	$	95,669	$	95,669	$	95,662	$	95,655

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GOODWILL

Goodwill represents the excess of the consideration transferred over the fair values of assets acquired and liabilities assumed from business combinations, and reflects the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. The goodwill balance is not deductible for income tax purposes.

The following table presents the activity of the goodwill balance for the years ended December 31, 2019, and 2018:

(In thousands)	Goodwill
Balance as of December 31, 2017	$	—
Goodwill resulting from business combination1	115,381
Adjustments during the period1	7,726
Foreign exchange differences	(2,554)
Balance as of December 31, 2018	120,553
Adjustments during the period2	10,196
Foreign exchange differences	(2,797)
Balance as of December 31, 2019	$	127,952

———

(1)Represents the excess purchase price over the estimated fair value of net assets acquired from Saeta and is primarily attributable to deferred tax liabilities and adjustment to the fair value of certain non-recourse project long-term debt. See Note 3. Acquisitions and Divestitures for additional details.

(2)Represents adjustments to the purchase price allocation of the assets acquired and liabilities assumed from the Saeta acquisition. See Note 3. Acquisitions and Divestitures for additional details.

8. LEASES

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment.

The components of lease expense were as follows:

(In thousands)	Year Ended December 31, 2019
Fixed operating lease cost	$	21,619
Variable operating lease cost1	5,884
Total operating lease cost	$	27,503

———

(1)Primarily related to production-based variable inputs and adjustments for inflation.

Supplemental cash flow information related to the Company’s leases was as follows:

(In thousands)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases1	$	16,485

———

(1)Right-of-use assets, excluding the effect of acquisitions, obtained in exchange for lease obligations during the year ended December 31, 2019, were not material.

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Supplemental balance sheet information related to the Company’s leases was as follows:

(In thousands, except lease term and discount rate)	As of December 31, 2019
Operating leases:
Right-of-use assets	$	288,321
Accounts payable, accrued expenses and other current liabilities	18,138
Operating lease obligations, less current portion	272,894
Total operating lease liabilities	$	291,032
Weighted Average Remaining Lease Term:
Operating leases	17.6
Weighted Average Discount Rate:
Operating leases	4.8		%

The maturities of the Company’s operating lease liabilities by fiscal year were as follows:

(In thousands)
2020	$	21,921
2021	21,828
2022	22,046
2023	22,220
2024	22,424
Thereafter	319,532
Total lease payments	429,971
Less: Imputed interest	(138,939)
Total	$	291,032

The following table summarizes the Company’s future commitments under operating leases as of December 31, 2018:

(In thousands)	2019		2020		2021		2022		2023		Thereafter		Total
Rent	$	20,002	$	20,005	$	20,241	$	20,410	$	20,577	$	331,425	$	432,660

The operating revenues from delivering electricity and the related products from owned solar and wind renewable energy facilities under PPAs in which the Company is the lessor, the majority of which is variable in nature, is recognized when electricity is delivered and is accounted for as rental income under the lease standard. The Company determines if an arrangement is a lease at contract inception, and if so, includes both lease and non-lease components as a single component and accounts for it as a lease. The Company’s PPAs do not contain any residual value guarantees or material restrictive covenants. The Company manages its risk associated with the residual value of its leased assets by retaining the ability to sell RECs through REC sale agreements. As a result of the adoption ASC 842 on January 1, 2019, the Company does not expect the future PPAs that it will enter into to meet the definition of a lease. See Note 2. Summary of Significant Accounting Policies for additional details.

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9. ASSET RETIREMENT OBLIGATIONS

The activity on asset retirement obligations for the years ended December 31, 2019, 2018 and 2017 was as follows:

	Year Ended December 31,
(In thousands)	2019		2018		2017
Balance as of January 1	$	212,657	$	154,515	$	148,575
Assumed through acquisition	33,143		68,441		—
Accretion expense	15,475		6,866		8,578
Extinguishment upon divestitures	(864)		—		(3,238)
Adjustment related to change in accretion period1	27,917		(15,734)		—
Other	—		843		—
Currency translation adjustments	(1,040)		(2,274)		600
Balance as of December 31	$	287,288	$	212,657	$	154,515

————

(1)Represents corrections related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement. The correction during the year ended December 31, 2019, recorded in the third quarter, resulted in $27.9 million increase in the carrying amounts of asset retirement obligations and the corresponding renewable energy facilities. The Company also recorded an adjustment to increase the previously reported accretion and depreciation expense by $3.3 million and $3.7 million, respectively, as a result of this change. The Company had recorded an adjustment during the fourth quarter of 2018, which resulted in a $15.7 million reduction in the Company’s asset retirement obligations and the corresponding renewable energy facilities’ carrying amounts as of December 31, 2018. The Company also recorded an adjustment during the fourth quarter of 2018 to reduce previously reported accretion and depreciation expense by $6.3 million as a result of this change. The Company evaluated these adjustments and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company’s consolidated financial statements for any prior period.

The Company did not have any assets that were legally restricted for the purpose of settling the Company’s asset retirement obligations as of December 31, 2019, 2018 and 2017.

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10. LONG-TERM DEBT

Long-term debt consisted of the following:

	As of December 31,				Interest Type	Interest Rate (%)1
(In thousands, except rates)	2019		2018				Financing Type
Corporate-level long-term debt2:
Senior Notes due 2023	$	500,000	$	500,000	Fixed	4.25	Senior notes
Senior Notes due 2025	—		300,000		Fixed	N/A	Senior notes
Senior Notes due 2028	700,000		700,000		Fixed	5.00	Senior notes
Senior Notes due 2030	700,000		—		Fixed	4.75	Senior notes
Revolver	—		377,000		Variable	N/A	Revolving loan
Term Loan	—		346,500		Variable	N/A	Term debt
Non-recourse long-term debt:
Permanent financing	3,854,386		3,496,370		Blended3	4.384	Term debt / senior notes
Bridge Facility	474,550		—		Variable	2.91	Term debt
Financing lease obligations	59,533		77,066		Imputed	5.804	Financing lease obligations
Total principal due for long-term debt and financing lease obligations	6,288,469		5,796,936			4.384
Unamortized discounts and premiums, net	(3,509)		(15,913)
Deferred financing costs, net	(49,578)		(19,178)
Less current portion of long-term debt and financing lease obligations	(441,951)		(464,332)
Long-term debt and financing lease obligations, less current portion	$	5,793,431	$	5,297,513

———

(1)As of December 31, 2019.

(2)Represents the debt issued by TerraForm Power Operating, LLC (“Terra Operating LLC”) and guaranteed by Terra LLC and certain subsidiaries of TerraForm Operating LLC other than non-recourse subsidiaries as defined in the relevant debt agreements (except for certain unencumbered non-recourse subsidiaries).

(3)Includes fixed rate debt and variable rate debt. As of December 31, 2019, 38% of this balance had a fixed interest rate and the remaining 62% of the balance had a variable interest rate. The Company entered into interest rate swap agreements to fix the interest rates of a majority of the variable rate permanent financing non-recourse debt (see Note 12. Derivatives).

(4)Represents the weighted average interest rate as of December 31, 2019.

Corporate-level Long-term Debt

Senior Notes

On January 28, 2015, Terra Operating LLC issued $800.0 million of 5.88%senior notes due 2023 at an offering price of 99.214% of the principal amount. On June 11, 2015, Terra Operating LLC issued an additional $150.0 million of 5.875% senior notes due 2023 (collectively, with the $800.0 million initially issued, the “Old Senior Notes due 2023”). The offering price of the additional $150.0 million of notes was 101.5% of the principal amount. On July 17, 2015, Terra Operating LLC issued $300.0 million of 6.125% senior notes due 2025 at an offering price of 100% of the principal amount (the “Senior Notes due 2025”).

On December 12, 2017, Terra Operating LLC issued $500.0 million of 4.25% senior notes due 2023 at an offering price of 100% of the principal amount (the “Senior Notes due 2023”) and $700.00 million of 5.00% senior notes due 2028 at an offering price of 100% of the principal amount (the “Senior Notes due 2028”). Terra Operating LLC used the net proceeds of the Senior Notes due 2023 and the Senior Notes due 2028 to redeem, in full, its Old Senior Notes due 2023, of which $950.0 million remained outstanding, at a redemption price that included a prepayment penalty of $50.7 million, plus accrued and unpaid interest, and to repay $150.0 million of revolving loans outstanding under the Revolver, as described below. As a result of the extinguishment of the Old Senior Notes due 2023, the Company recognized a $72.3 million loss on extinguishment of debt during the year ended December 31, 2017, consisting of the $50.7 million prepayment penalty and the write-off of $21.6 million of unamortized deferred financing costs and debt discounts as of the redemption date.

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On October 16, 2019, Terra Operating LLC issued $700.0 million aggregate principal amount of 4.75% senior notes due on January 15, 2030, at an offering price of 100% of the principal amount (the “Senior Notes due 2030” and, together with the Senior Notes due 2023 and the Senior Notes due 2028, the “Senior Notes”), in an unregistered offering pursuant to Rule 144A under the Securities Act. Terra Operating LLC used the net proceeds from the Senior Notes due 2030 to (i) redeem, in full, the Senior Notes due 2025, of which $300.0 million remained outstanding, at a redemption price that included a prepayment penalty of $18.4 million, plus accrued interest, (ii) redeem, in full, the Company’s Term Loan (as defined below), of which $343.9 million remained outstanding plus accrued interest, (iii) redeem, in full, derivative liabilities related to interest rate swaps with hedge counterparties of which $8.8 million remained outstanding, and (iii) pay for the fees and expenses related to the issuance.

The Senior Notes are senior obligations of Terra Operating LLC and are guaranteed by Terra LLC and each of Terra Operating LLC’s subsidiaries that guarantee the Revolver (as defined below) or certain other material indebtedness of Terra Operating LLC or Terra LLC. Each series of the Senior Notes rank equally in right of payment with all existing and future senior indebtedness of Terra Operating LLC, including the Revolver, senior in right of payment to any future subordinated indebtedness of Terra Operating LLC, and effectively subordinated to all borrowings under the Revolver, which are secured by substantially all of the assets of Terra Operating LLC and the guarantors of the Senior Notes.

At its option, Terra Operating LLC may redeem some or all of each series of the Senior Notes at any time or from time to time before their maturity. If Terra Operating LLC elects to redeem the Senior Notes due 2023 prior to October 31, 2022, the Senior Notes due 2028 before July 31, 2027, or the Senior Notes due 2030 before January 15, 2025, Terra Operating LLC would be required to pay a prepayment penalty as set forth in the applicable indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2030 between January 15, 2025 and January 14, 2028, Terra Operating LLC would be required to pay a call premium as set forth in the applicable indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2023, the Senior Notes due 2028, or the Senior Notes due 2030 on or after these respective dates, Terra Operating LLC would be required to pay a redemption price equal to 100% of the aggregate principal amount of the Senior Notes redeemed plus accrued and unpaid interest thereon. If certain change of control triggering events occur in the future, Terra Operating LLC must offer to repurchase all of each series of the Senior Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the repurchase date.

Term Loan

On November 8, 2017, Terra Operating LLC entered into a 5-year $350.0 million senior secured term loan (the “Term Loan”) and used the net proceeds to repay outstanding borrowings under a non-recourse project-level term debt and $50.0 million of revolving loans outstanding under the Revolver. The Term Loan originally bore interest at a rate per annum equal to, at Terra Operating LLC’s option, either (i) a base rate plus a margin of 1.75% or (ii) a reserve adjusted Eurodollar rate plus a margin of 2.75%, and is secured and guaranteed equally and ratably with the Revolver. The Term Loan provided for voluntary prepayments, in whole or in part, subject to notice periods. There were no prepayment penalties or premiums other than customary breakage costs after the six-month anniversary of the closing date. Within the first six months following the closing date, a prepayment premium of 1.00% would apply to any principal amounts that were prepaid. On May 11, 2018, Terra Operating LLC entered into an amendment to the Term Loan, whereby the interest rate was reduced by 0.75% per annum. The Company recognized a $1.5 million loss on extinguishment of debt during the year ended December 31, 2018, as a result of this amendment representing write-offs of certain deferred debt financing costs. On March 8, 2019, the Company entered into interest rate swap agreements with counterparties to hedge the cash flows associated with the interest payments on the entire principal of the Term Loan, paying an average fixed rate of 2.54%. In return, the counterparties agreed to pay the variable interest payments due to the lenders until maturity. On October 17, 2019, Terra Operating LLC repaid, in full, the amounts outstanding, including the accrued interest, under the Term Loan using the proceeds of the offering of the Senior Notes due 2030. The Company recognized a loss on extinguishment of $4.0 million for the year ended December 31, 2019, representing write-offs of deferred debt financing costs.

Revolver

On October 17, 2017, Terra Operating LLC entered into a new senior secured revolving credit facility (the “Revolver”) in an initial amount of $450.0 million, available for revolving loans and letters of credit, and maturing in October 2021. All outstanding amounts originally bore interest at a rate per annum equal to, at Terra Operating LLC’s option, either (i) a base rate plus a margin ranging between 1.25% to 2.00% or (ii) a reserve adjusted Eurodollar rate plus a margin ranging between 2.25% to 3.00%. In addition to paying interest on outstanding principal under the Revolver, Terra Operating LLC is required to pay a standby fee in respect of the unutilized commitments thereunder, payable quarterly in arrears. This standby fee ranges between 0.375% and 0.50% per annum. The Revolver provides for voluntary prepayments, in whole or in part, subject to notice periods. There are no prepayment penalties or premiums other than customary breakage costs. On February 6, 2018, Terra Operating

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LLC entered into an amendment to increase the facility limit to $600.0 million. On October 5, 2018, Terra Operating LLC entered into an amendment to (i) reduce the interest rate by 0.75% per annum, and (ii) extend the maturity date of the Revolver to October 2023. The Revolver currently bears interest at a rate equal to, at Terra Operating LLC’s option, either (i) a reserve adjusted Eurodollar rate plus an applicable margin ranging from 1.50% to 2.25% per annum, or (ii) a base rate plus an applicable margin ranging from 0.50% to 1.25% per annum. The Company did not incur additional debt or receive any proceeds in connection with the October 5, 2018 amendment.

Under the Revolver, each of Terra Operating LLC’s existing and subsequently acquired or organized domestic restricted subsidiaries (excluding non-recourse subsidiaries) and Terra LLC are or will become guarantors. The Revolver, each guarantee and any interest rate, currency hedging or hedging of REC obligations of Terra Operating LLC or any guarantor owed to the administrative agent, any arranger or any lender under the Revolver is secured by first priority security interests in (i) all of Terra Operating LLC’s, each guarantor’s and certain unencumbered non-recourse subsidiaries’ assets, (ii) 100% of the capital stock of each of Terra Operating LLC and its domestic restricted subsidiaries and 65% of the capital stock of Terra Operating LLC’s foreign restricted subsidiaries and (iii) all intercompany debt. The Revolver is secured equally and ratably with the Term Loan.

On October 8, 2019, Terra Operating LLC entered into an amendment to the Revolver agreement (the “Upsize Amendment”) whereby (i) the aggregate size of the commitments to make revolving loans (‘‘Revolving Loans’’) under the Revolver was increased by $200.0 million to $800.00 million, shared ratably among the lenders of October 8, 2019, (ii) the aggregate size of the letter of credit facility under the Revolver was increased by $50.0 million to $300.0 million and (iii) the accordion feature of the Revolver, which allows for further increases to the commitments to make Revolving Loans, was set at $150.0 million. Additionally, the Upsize Amendment extended the maturity date of the Revolver by one year to October 5, 2024.

Sponsor Line Agreement

On October 16, 2017, TerraForm Power, Inc. entered into a credit agreement (the “Sponsor Line”) with Brookfield and one of its affiliates. The Sponsor Line establishes a $500.0 million secured revolving credit facility and provides for the lenders to commit to making LIBOR loans to the Company during a period not to exceed three years from the effective date of the Sponsor Line (subject to acceleration for certain specified events). The Company may only use the revolving Sponsor Line credit facility to fund all or a portion of certain funded acquisitions or growth capital expenditures. The Sponsor Line terminates, and all obligations thereunder become payable, no later than October 16, 2022.

Borrowings under the Sponsor Line bear interest at a rate per annum equal to a LIBOR rate determined by reference to the costs of funds for U.S. dollar deposits for the interest period relevant to such borrowing adjusted for certain additional costs, in each case plus 3.00% per annum. In addition to paying interest on outstanding principal under the Sponsor Line, the Company is required to pay a standby fee of 0.50% per annum in respect of the unutilized commitments thereunder, payable quarterly in arrears. The Company is permitted to voluntarily reduce the unutilized portion of the commitment amount and repay outstanding loans under the Sponsor Line at any time without premium or penalty, other than customary “breakage” costs. TerraForm Power’s obligations under the Sponsor Line are secured by first-priority security interests in substantially all assets of TerraForm Power, including 100% of the capital stock of Terra LLC, in each case subject to certain exclusions set forth in the credit documentation governing the Sponsor Line. Under certain circumstances, the Company may be required to prepay amounts outstanding under the Sponsor Line.

During the year ended December 31, 2018, the Company made two draws on the Sponsor Line totaling $86.0 million. The Company used the proceeds to fund the acquisition of Saeta and were repaid in full as of December 31, 2018. The Company did not make any draws on the Sponsor Line during the years ended December 31, 2019, and 2017. See Note 21. Related Parties for details.

Covenants and Cross-defaults 

The terms of the Company’s corporate-level debt agreements and indentures include customary affirmative and negative covenants and provide for customary events of default, which include, among others, nonpayment of principal or interest and failure to timely deliver financial statements, including quarterly financial maintenance covenants for the Revolver. The occurrence of an event of default for one corporate-level debt instrument could also cause a cross-default for the other corporate-level debt instruments, as described below.

Pursuant to both the terms of the Revolver and the Term Loan, a default of more than $75.0 million of indebtedness (other than non-recourse indebtedness, and indebtedness under the Sponsor Line, which is an obligation of the Company),

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including under these respective agreements, would result in a cross-default under the respective agreements that would permit the lenders holding more than 50% of the aggregate exposure under each to accelerate any outstanding principal amount of loans, terminate any outstanding letter of credit and terminate the outstanding commitments (as applicable to each).

Pursuant to the terms of the Senior Notes, a default of indebtedness that exceeds the greater of (i) $100.0 million for the Senior Notes due 2023 and Senior Notes due 2028, and $140.0 million for the Senior Notes due 2030, or (ii) 1.5% of the Company’s consolidated total assets (other than non-recourse indebtedness and indebtedness under the Sponsor Line, which is an obligation of TerraForm Power), that is (i) caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period provided in such indebtedness on the date of such default or (ii) results in the acceleration of such indebtedness would give the trustee under the respective indentures or the holders of at least 25% in the aggregate principal amount of the then outstanding Senior Notes under the respective indentures the right to accelerate any outstanding principal amount of loans and terminate the outstanding commitments under the respective indentures.

An event of default of more than $75.0 million of indebtedness under the Revolver, Term Loan and each series of the Senior Notes would trigger an event of default under the Sponsor Line that would permit the lenders to accelerate any outstanding principal amount of loans and terminate the outstanding commitments under the Sponsor Line.

Non-recourse Long-term Debt

Certain subsidiaries of the Company have incurred long-term non-recourse debt obligations related to the renewable energy facilities that those subsidiaries own directly or indirectly. The indebtedness of these subsidiaries is typically secured by the renewable energy facilities or equity interests in subsidiaries that directly or indirectly hold renewable energy facilities with no recourse to TerraForm Power, Terra LLC or Terra Operating LLC other than limited or capped contingent support obligations, which in aggregate are not considered material to the Company’s business and financial condition. In connection with these financings and in the ordinary course of its business, the Company and its subsidiaries observe formalities and operating procedures to maintain each of their separate existence and can readily identify each of their separate assets and liabilities as separate and distinct from each other. As a result, these subsidiaries are legal entities that are separate and distinct from each of TerraForm Power, Terra LLC, Terra Operating LLC and the guarantors under the Senior Notes due 2023, the Senior Notes due 2028, the Senior Notes due 2030, the Revolver and the Sponsor Line.

2019 United States Project Financings

On May 29, 2019, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement of $104.1 million senior secured term loan facility, and secured by approximately 137.7 MW of distributed generation solar power facilities located in the U.S. that are owned by certain subsidiaries of the Company. The Company used the net proceeds of this debt to repay a portion of the Revolver and general corporate purposes. The debt bears interest at a rate per annum equal to three month LIBOR plus an applicable margin of 200 basis points that increases by 12.5 basis points every four years until maturity. The debt matures on May 26, 2034, and amortizes on a fifteen-year sculpted amortization schedule. The Company entered into interest rate swap agreements with counterparties to hedge the interest payments associated with the debt, paying a fixed rate of 2.3%. In return, the counterparties agreed to pay the variable interest payments to the lenders.

On August 30, 2019, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement issuing $131.0 million of 3.2% senior notes secured by approximately 111 MW of utility-scale wind power plants located in the United States that are owned by certain subsidiaries of the Company. The Company used the net proceeds of this debt to repay a portion of the balance outstanding under the Revolver. The senior secured notes mature on July 2, 2032 and amortize on an approximately thirteen-year sculpted amortization schedule.

On September 25, 2019, one of the Company’s subsidiaries entered into a $475.0 million new non-recourse senior term loan (“Bridge Facility”) secured by the approximately 320 MW portfolio of distributed generation power facilities located in the United States that were acquired from subsidiaries of AltaGas. The Bridge Facility bears interest at a rate per annum equal to LIBOR plus an applicable margin of 100 basis points for the first six months, 150 basis points for the following six months and 175 basis points thereafter. The Company used the net proceeds of this debt to fund a portion of the purchase price of the WGL Acquisition. See Note 3. Acquisitions and Divestitures for additional details. The Bridge Facility matures on September 24, 2020. The Company has a one-year extension option and intends, through its subsidiaries, to complete a refinancing of the balance on a long-term basis before maturity in a series of two or more transactions. The balance, net of a principal repayment and unamortized deferred financing costs, is included within non-current liabilities in the consolidated balance sheets.

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On November 25, 2019, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement issuing $171.5 million of 3.55% senior notes secured by approximately 200.6 MW utility-scale wind power plants located in the United States. The Company used the net proceeds of this debt to (i) redeem, in full, the outstanding balance of the non-recourse project term debt previously incurred by the subsidiary, of which $69.1 million remained outstanding plus accrued and unpaid interest, (ii) redeem, in full, derivative liabilities related to interest rate swaps with hedge counterparties of which $9.8 million remained outstanding and (iii) pay for the fees and expenses related to the issuance. The Company used the remaining proceeds for general corporate purposes. As a result of the extinguishment of the project-level debt, the Company recognized a $0.3 million loss on extinguishment of debt during the year ended December 31, 2019, representing the write-off of unamortized debt discount as of the redemption date. The senior secured notes mature on May 1, 2039, and amortize on a twenty-year amortization schedule.

2019 Spain Project Financings

On December 10, 2019, five of the Company’s subsidiaries completed a €235.8 million refinancing agreement (equivalent to $264.4 million at the closing date) of certain non-recourse indebtedness associated with 236.0 MW utility-scale wind plants located in Spain (the “Spanish Wind Term Loans”). The Spanish Wind Term Loans bear interest at a rate per annum equal to three months Euribor plus an applicable margin of 165 basis points that increases by 20 basis points every five years throughout maturity. The Spanish Wind Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through December 2033. The Company entered into interest rate swap agreements with counterparties to hedge approximately 80% of the cash flows associated with the debt, paying a fixed rate of 1.55%. In return, the counterparties agreed to pay the variable interest payments to the lenders. The Company used the net proceeds of the refinancing to fund a portion of the purchase price of the X-Elio Acquisition.

On December 27, 2019, one of the Company’s subsidiaries completed a €213.6 million refinancing agreement of certain non-recourse indebtedness, representing an upsize of approximately €42.0 million (equivalent to $239.5 million and $47.1 million at the closing date, respectively), of certain non-recourse indebtedness associated with approximately 50.0 MW concentrated solar power facility located in Spain (the “Spanish Solar Term Loans”). The Spanish Solar Term Loans consist of €146.4 million variable-rate tranche and €67.2 million fixed-rate tranche (equivalent to $164.2 million and $75.3 million, respectively). The variable-rate tranche bears interest at a rate per annum equal to three months Euribor plus an applicable margin of 190 basis points that increases by 20 basis points every five years throughout the maturity in December of 2033. The fixed-rate tranche bears interest at a rate of 2.55% and matures on June 30, 2035. The Spanish Solar Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through 2035. The Company entered into interest rate swap agreements with counterparties to hedge approximately 80% of the variable cash flows of the debt, paying an average fixed rate of 3.70%. In return, the counterparty agreed to pay the variable interest payments to the lenders. The Company used the net proceeds of the refinancing for general corporate purposes.

2019 Uruguay Project Financing

On April 30, 2019, two of the Company’s subsidiaries completed a $204.0 million refinancing agreements of certain non-recourse indebtedness, representing a net upsize of approximately $57.5 million, associated with the Company’s 95 MW of utility-scale wind plants located in Uruguay (the “Uruguay Term Loans”). The Uruguay Term Loans consist of a $103.0 million Tranche A loan, a new $72.0 million Tranche B loan, and an additional $29.0 million senior secured term loan. Approximately 46% of the combined principal amount of the Uruguay Term Loans bears a fixed interest rate of 2.6%, and the remainder bears interest at a rate per annum equal to six-month U.S. LIBOR plus an applicable margin that ranges from 1.94% to 2.94%. The Uruguay Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through December 2035. The Company entered into interest rate swap agreements with a counterparty to hedge greater than 90% of the cash flows associated with the variable portion of the debt, paying a fixed rate of 2.78%. In return, the counterparty agreed to pay the variable interest payments to the lenders. The net proceeds of the refinancing were used to pay down a portion of the Revolver and general corporate purposes.

Indebtedness Assumed on Acquisition

In connection with the X-Elio Acquisition, the Company assumed $151.7 million of project-level debt secured by the renewable energy facilities of the related entities. The average interest rates applicable to this assumed indebtedness was 2.8%. As of December 31, 2019, the Company obtained all required change of control consents from the lenders.

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Financing Lease Obligations

In certain transactions, the Company accounts for the proceeds of sale-leasebacks as financings, which are typically secured by the renewable energy facility asset and its future cash flows from energy sales, with no recourse to Terra LLC or Terra Operating LLC under the terms of the arrangement.

Non-recourse Debt Defaults

As of December 31, 2019 and December 31, 2018, the Company reclassified $159.3 million and $166.4 million, respectively, of non-recourse long-term indebtedness, net of unamortized deferred financing costs and debt discounts, to current in the consolidated balance sheets due to defaults remaining as of the respective financial statements issuance dates. The defaults as of December 31, 2019 primarily consisted of indebtedness of the Company’s renewable energy facility in Chile. The Company continues to amortize deferred financing costs and debt discounts over the maturities of the respective financing agreements as before the violations, since the Company believes there is a reasonable likelihood that it will be, in due course, able to successfully negotiate waivers with the lenders and/or cure existing defaults. The Company’s management based this conclusion on (i) its past history of obtaining waivers and/or forbearance agreements with lenders, (ii) the nature and existence of active negotiations between the Company and the respective lenders to secure waivers, (iii) the Company’s timely servicing of these debt instruments and (iv) the fact that no non-recourse financing has been accelerated to date and no project-level lender has notified the Company of such lenders election to enforce project security interests.

See Note 5. Cash and Cash Equivalents for discussion of corresponding restricted cash reclassifications to current as a result of these defaults.

Modification and Extinguishment of Debt

Net loss on modification and extinguishment of debt includes prepayment penalties, the write-off of unamortized deferred financing costs and debt premiums or discounts, costs incurred in a debt modification that are not capitalized as deferred financing costs, other costs incurred in relation to debt extinguishment, and any gain from the redemption of debt below its carrying amount. Loss on modification and extinguishment of debt, net in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, were attributable to the following:

	Year Ended December 31,
(In thousands)	2019		2018		2017
Senior Notes due 20251	$	22,827	$	—	$	—
Old Senior Notes due 20231	—		—		72,277
Term Loan1	4,006		1,480		—
The Old Revolver2	—		—		8,822
Non-recourse wind project financing in the U.S.1	313		—		—
Non-recourse wind project financing in Spain1	3,949		—		—
Solar financing lease obligation in the U.S.3	(4,142)		—		—
Total loss on modification and extinguishment of debt, net	$	26,953	$	1,480	$	81,099

———

(1)See above for additional details.

(2)The Company recognized a loss on modification and extinguishment of debt as a result of the reduction of the borrowing capacity of the old revolving credit facility (the “Old Revolver”) and its termination during the year ended December 31, 2017.

(3)The Company recognized a net gain on extinguishment of debt due to the redemption of certain financing lease obligations within the distributed generation Solar portfolio. The difference between the cash paid to redeem the obligations and the carrying amount as of the date of extinguishment was recognized as a loss on extinguishment of debt in the consolidated statements of operations.

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Minimum Lease Payments

The aggregate amounts of minimum lease payments on the Company’s financing lease obligations are $59.5 million. Contractual obligations for the years 2020 through 2024 and thereafter, are as follows:

(In thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Minimum lease obligations1	$	3,091	$	3,171	$	3,126	$	4,310	$	2,933	$	42,902	$	59,533

———

(1)Represents the minimum lease payment due dates for the Company’s financing lease obligations and does not reflect the reclassification of $9.8 million of financing lease obligations to current as a result of debt defaults under certain of the Company’s non-recourse financing arrangements.

Maturities

The aggregate contractual principal payments of long-term debt due after December 31, 2019, excluding financing lease obligations and amortization of debt deferred financing costs, as stated in the financing agreements, are as follows:

(In thousands)	20202		2021		2022		2023		2024		Thereafter		Total
Maturities of long-term debt1	$	742,664	$	273,160	$	437,168	$	770,276	$	279,648	$	3,726,020	$	6,228,936

———

(1)Represents the contractual principal payment due dates for the Company’s long-term debt and does not reflect the reclassification of $159.3 million of long-term debt, net of unamortized deferred financing costs of $5.7 million, to current due to debt defaults that existed as of the date of the issuance of the financial statements (see above for additional details) as of December 31, 2019.

(2)Includes the $474.6 million Bridge Facility maturing on September 24, 2020. The Company has a one-year extension option and intends, through its subsidiaries, to complete a refinancing of the balance on a long-term basis prior to maturity. The balance, net of unamortized deferred financing costs, is included within non-current liabilities in the consolidated balance sheets.

11. INCOME TAXES

The income tax expense (benefit) was calculated based on the income and losses before income tax between U.S. and foreign operations as follows:

(In thousands)	2019		2018		2017
(Loss) income before income taxes:
United States	$	(212,995)	$	(182,289)	$	(292,190)
Foreign	18,308		16,672		36,246
Loss before income taxes	$	(194,687)	$	(165,617)	$	(255,944)

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The income tax provision consisted of the following:

(In thousands)	Current		Deferred		Total
Year ended December 31, 2019
U.S. federal	$	145	$	4,728	$	4,873
State and local	134		3,197		3,331
Foreign	4,636		(942)		3,694
Total expense	4,915		6,983		11,898
Tax benefit in equity	—		(978)		(978)
Total	$	4,915	$	6,005	$	10,920
Year ended December 31, 2018
U.S. federal	$	(461)	$	(18,301)	$	(18,762)
State and local	323		(4,376)		(4,053)
Foreign	2,739		7,786		10,525
Total expense (benefit)	2,601		(14,891)		(12,290)
Tax expense in equity	—		2,826		2,826
Total	$	2,601	$	(12,065)	$	(9,464)
Year ended December 31, 2017
U.S. federal	$	(45)	$	(20,489)	(20,534)
State and local	95		(1,211)		(1,116)
Foreign	220		1,789		2,009
Total expense (benefit)	270		(19,911)		(19,641)
Tax expense in equity	—		14,081		14,081
Total	$	270	$	(5,830)	$	(5,560)

Effective Tax Rate

The income tax provision differed from the expected amounts computed by applying the statutory U.S. federal income tax rate of 21% as of December 31, 2019 and December 31, 2018 and 35% as of December 31, 2017, to loss before income taxes, as follows:

	Year Ended December 31,
	2019		2018		2017
Income tax benefit at U.S. federal statutory rate	21.0	%	21.0	%	35.0	%
Increase (reduction) in income taxes:
State income taxes, net of U.S. federal benefit	5.9		5.0		4.0
Foreign operations	(2.0)		(0.5)		8.7
Non-controlling interests	(8.0)		(25.9)		(9.4)
Permanent differences	(0.2)		(1.6)		—
Tax Act rate change impact	—		—		2.0
Return to provision	—		—		2.8
Change in valuation allowance	(22.4)		7.8		(34.1)
Other	(0.4)		1.6		—
Effective tax rate	(6.1)	%	7.4	%	9.0	%

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Prior to the consummation of the Merger on October 16, 2017, TerraForm Power owned approximately 66% of Terra LLC and SunEdison owned approximately 34% of Terra LLC. On October 16, 2017, pursuant to the Settlement Agreement, SunEdison transferred its interest in Terra LLC to TerraForm Power. Since the date of this transaction, TerraForm Power owns 100% of the capital and profits interest in Terra LLC, except for the IDRs which are owned by Brookfield IDR Holder. The Merger resulted in a change in control to occur subjecting TerraForm Power’s loss carryforwards to be limited for future usage under Internal Revenue Code Section 382.

On December 31, 2018, the Company executed a reorganization of its Capital Dynamics portfolio which resulted in no current tax impact by effectively moving the stock of the Capital Dynamics corporate entities up to TerraForm Power and then immediately contributing Capital Dynamics project assets to Terra LLC. The Company recognized a deferred tax benefit of $20.1 million during the year ended December 31, 2018, resulting from an excess net deferred tax liability that was previously recognized by TerraForm Power Holdings, Inc. as a separate taxpayer which is now expected to reverse in future periods as part of the U.S. federal and state tax consolidated group and provide a source of future taxable income to realize the Company’s net operating loss (“NOL”) carryforwards.

For the years ended December 31, 2019 and December 31, 2018, the overall effective tax rate was different than the statutory rate of 21% primarily due to the recording of a valuation allowance on certain income tax benefits attributed to the Company, losses allocated to non-controlling interests, the 2018 revaluation of deferred federal and state tax balances for TerraForm Power Holdings, Inc., and the effect of foreign and state taxes. For the year ended December 31, 2017, the overall effective tax rate was different from the statutory tax rate of 35% primarily due to the recording of a valuation allowance on certain income tax benefits attributed to the Company, losses allocated to non-controlling interests, the 2017 revaluation of deferred federal and state tax balances and the effect of foreign and state taxes.

The tax effects of the major items recorded as deferred tax assets and liabilities were as follows:

	As of December 31,
(In thousands)	2019		2018
Deferred tax assets:
Net operating losses and tax credit carryforwards	$	623,858	$	587,833
Derivative Liabilities	26,087		33,261
Interest expense limitation carryforward	117,598		67,887
Total deferred tax assets	767,543		688,981
Valuation allowance	(413,884)		(386,336)
Net deferred tax assets	353,659		302,645
Deferred tax liabilities:
Investment in partnership	270,237		221,694
Renewable energy facilities	107,908		30,261
Intangible assets	169,195		229,363
Other	858		176
Total deferred tax liabilities	548,198		481,494
Net deferred tax liabilities	$	194,539	$	178,849

For U.S. income tax purposes, Terra LLC is taxed as a U.S. partnership and controls the underlying renewable energy facilities. Thus, the tax effects of temporary differences related to the Company’s portfolio companies are captured within the net deferred tax liability for the investment in the partnership. At December 31, 2019, the Company has gross NOL carryforwards of $2.29 billion in the U.S. and gross NOL carryforwards of $132.1 million in foreign jurisdictions that will both expire in tax years beginning in 2035. Of the $2.3 billion of gross NOL carryforwards generated in the U.S., approximately $0.56 billion are limited and are expected to expire unused. For the remaining $1.73 billion, the Company does not believe it is more likely than not that it will generate sufficient taxable income to realize this entire amount. Consequently, the Company has recorded a valuation allowance against its deferred tax assets, net of the deferred tax liability related to the Company’s partnership investments that is expected to reverse within the NOL carryforward period with the exception of certain NOL at its Canadian, Portuguese, Spanish and Uruguayan operations. The current year movement in the valuation allowance is related to losses generated in the current year as a result of the current year operations and changes in the Company’s tax accounting methods and the limitations on such U.S. Federal and State losses as a result of U.S. Tax Reform.

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Prior to the acquisition of Saeta, the Company’s foreign entities had cumulative negative earnings and profits, therefore, those entities had no earnings to repatriate back to the U.S. Following the enactment of the Tax Act and the current year acquisition of Saeta, the Company does not assert the indefinite reinvestment related to undistributed earnings of its foreign subsidiaries. The Company plans to utilize earnings generated by its foreign subsidiaries to make strategic acquisitions abroad and repatriate any excess earnings. The Company’s management determined there was no material deferred tax liabilities that needed to be recognized as of December 31, 2019.

The 2017 Tax Act included a provision to tax global intangible low tax income (“GILTI”) of foreign subsidiaries in excess of a standard rate of return. The Company will record expense related to GILTI in the period the tax is incurred. For the year ended December 31, 2019, the Company was in an overall tested loss position for GILTI purposes and therefore has not included GILTI in its calculation of taxable loss. The U.S. Treasury has issued additional guidance through notices and final regulations during 2019 which did not significantly impact the Company’s interpretation of the 2017 Tax Act. The Company will continue to monitor developments as they occur.

As of December 31, 2019 and 2018, the Company had not identified any uncertain tax positions for which a liability was required under ASC 740-10.

12. DERIVATIVES

As part of its risk management strategy, the Company entered into derivative instruments which include interest rate swaps, foreign currency contracts and commodity contracts to mitigate interest rate, foreign currency and commodity price exposures. If the Company elects to do so and if the instrument meets the criteria specified in ASC 815, Derivatives and Hedging, the Company designates its derivative instruments as either cash flow hedges or net investment hedges. The Company enters into interest rate swap agreements in order to hedge the variability the of expected future cash interest payments. Foreign currency contracts are used to reduce risks arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of these practices is to minimize the impact of foreign currency fluctuations on operating results. The Company also enters into commodity contracts to hedge price variability inherent in energy sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot energy prices and stabilize estimated revenue streams. The Company does not use derivative instruments for trading or speculative purposes.

As of December 31, 2019 and 2018, the fair values of the following derivative instruments were included in the respective balance sheet captions indicated below:

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	Fair Value of Derivative Instruments1
	Derivatives Designated as Hedging Instruments						Derivatives Not Designated as Hedging Instruments
(In thousands)	Interest Rate Swaps		Foreign Currency Contracts		Commodity Contracts		Interest Rate Swaps		Foreign Currency Contracts		Commodity Contracts		Gross Derivatives		Counterparty Netting2		Net Derivatives
As of December 31, 2019
Derivative assets, current	$	—	$	349	$	1,040	$	—	$	8,092	$	7,279	$	16,760	$	(941)	$	15,819
Derivative assets	809		24		33,269		—		504		23,583		58,189		(472)		57,717
Total assets	$	809	$	373	$	34,309	$	—	$	8,596	$	30,862	$	74,949	$	(1,413)	$	73,536
Derivative liabilities, current	$	12,046	$	631	$	—	$	21,923	$	310	$	—	$	34,910	$	(941)	$	33,969
Derivative liabilities	41,605		315		—		59,412		534		—		101,866		(472)		101,394
Total liabilities	$	53,651	$	946	$	—	$	81,335	$	844	$	—	$	136,776	$	(1,413)	$	135,363
As of December 31, 2018
Derivative assets, current	$	1,478	$	605	$	18	$	—	$	3,344	$	9,783	$	15,228	$	(857)	$	14,371
Derivative assets	5,818		2,060		42,666		—		647		40,137		91,328		(344)		90,984
Total assets	$	7,296	$	2,665	$	42,684	$	—	$	3,991	$	49,920	$	106,556	$	(1,201)	$	105,355
Derivative liabilities, current	$	465	$	—	$	—	$	34,267	$	1,684	$	—	$	36,416	$	(857)	$	35,559
Derivative liabilities	3,334		1,437		—		88,034		1,387		—		94,192		(344)		93,848
Total liabilities	$	3,799	$	1,437	$	—	$	122,301	$	3,071	$	—	$	130,608	$	(1,201)	$	129,407

———

(1)Fair value amounts are shown before the effects of counterparty netting adjustments.

(2)Represents the netting of derivative exposures covered by qualifying master netting arrangements.

As of December 31, 2019 and December 31, 2018, the Company had posted letters of credit in the amount of $15.0 million, as collateral related to certain commodity contracts. Certain derivative contracts contain provisions providing the counterparties a lien on specific assets as collateral. There was no cash collateral received or pledged as of December 31, 2019 and December 31, 2018 related to the Company’s derivative transactions.

The Company elected to present all derivative assets and liabilities on a net basis on the consolidated balance sheets as a right to set-off exists. The Company enters into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements with its counterparties. An ISDA Master Agreement is an agreement that can govern multiple derivative transactions between two counterparties that typically provides for the net settlement of all, or a specified group, of these derivative transactions through a single payment, and in a single currency, as applicable. A right to set-off typically exists when the Company has a legally enforceable ISDA Master Agreement. No amounts were netted for commodity contracts as of December 31, 2019 or 2018 as each of the commodity contracts were in a gain position.

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The following table presents the notional amounts of derivative instruments as of December 31, 2019 and 2018:

	December 31,
(In thousands)	2019	2018
Derivatives designated as hedging instruments:
Cash flow hedges:
Interest rate swaps (USD)	441,628	357,797
Interest rate swaps (CAD)	138,575	147,522
Interest rate swaps (EUR)	310,721	—
Commodity contracts (MWhs)	5,360	6,030
Net investment hedges:
Foreign currency contracts (CAD)	94,100	81,600
Foreign currency contracts (EUR)	199,750	320,000
Derivatives not designated as hedging instruments:
Interest rate swaps (USD)	11,399	12,326
Interest rate swaps (EUR)1	745,719	1,044,253
Foreign currency option contracts (EUR)2	625,200	—
Foreign currency forward contracts (EUR)2	118,550	640,200
Commodity contracts (MWhs)	7,610	8,707

————

(1)Represents the notional amount of the interest rate swaps at Saeta to economically hedge the interest rate payments on non-recourse debt. The Company did not designate these derivatives as hedging instruments per ASC 815 as of the respective balance sheet dates.

(2)Represents the notional amount of foreign currency contracts used to economically hedge portions of the Company’s foreign exchange risk associated with Euro-denominated intercompany loans. The Company did not designate these derivatives as hedging instruments per ASC 815 as of December 31, 2019 and December 31, 2018.

Gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018 and 2017 consisted of the following:

	Location of Loss (Gain) in the Statements of Operations	Year Ended December 31,
(In thousands)		2019		2018		2017
Interest rate swaps	Interest expense, net	$	25,790	$	2,565	$	3,161
Foreign currency contracts	Gain on foreign currency exchange, net	(27,233)		(34,714)		966
Commodity contracts	Operating revenues, net	479		3,209		(5,117)

During the second quarter of 2018, the Company discontinued hedge accounting for a certain long-dated commodity contract as it was no longer considered highly effective in offsetting the cash flows associated with the underlying risk being hedged. Long-term electricity prices in the related market declined significantly during the second quarter of 2018, causing the option component of the derivative contract to have an intrinsic value which negatively impacted the effectiveness assessment of the hedge relationship. Hedge accounting was prospectively discontinued effective April 1, 2018, with changes in fair value recorded in earnings. The gains in AOCI as of March 31, 2018 amounted to $44.3 million and $5.7 million of which were recorded in earnings during the three quarters following the discontinuation of hedge accounting. The balance of the accumulated gains deferred in AOCI as of December 31, 2019 was $30.9 million will be amortized through earnings over the term of the contract, which expires in 2023, of which $7.7 million will be amortized within the next 12 months.

As discussed in Note 3. Acquisitions and Divestitures, the Company consummated the sale of the U.K. Portfolio on May 11, 2017. As part of the sale agreement, Vortex Solar UK Limited assumed the debt and the associated interest rate swaps. As of the date of the sale, the remaining loss in AOCI of $0.4 million was reclassified into interest expense, net, and the fair value of the interest rate swap liability of $23.4 million is reflected within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017. The interest expense amount reflected in the table above for the year ended December 31, 2017 primarily pertains to these interest rate swaps.

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Gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018 and 2017 consisted of the following:

	Year Ended December 31,
Derivatives in Cash Flow and Net Investment Hedging Relationships	Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes1						Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach2
(In thousands)	2019		2018		2017		2019		2018		2017
Interest rate swaps	$	(33,503)	$	1,034	$	(396)	$	—	$	—	$	—
Foreign currency contracts	13,904		11,169		—		—		—		—
Commodity derivative contracts	(8,920)		(3,163)		18,008		—		452		—
Total	$	(28,519)	$	9,040	$	17,612	$	—	$	452	$	—

	Year Ended December 31,
Location of Amount Reclassified from AOCI into Income	(Gain) Loss Included in the Assessment of Effectiveness Reclassified from AOCI into Income3						(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings
	2019		2018		2017		2019		2018		2017
Interest expense, net	$	1,896	$	1,307	$	5,507	$	—	$	—	$	(1,270)
Gain on foreign currency exchange, net	—		—		—		—		—		—
Operating revenues, net	3,371		(1,804)		(7,754)		—		—		(2,923)
Total	$	5,267	$	(497)	$	(2,247)	$	—	$	—	$	(4,193)

———

(1)Net of $(1.0) million, $3.6 million, and $(0.1) million tax (benefit) expense attributed to interest rate swaps during the years ended December 31, 2019, 2018, and 2017, respectively. Net of $3.9 million tax expense attributed to foreign currency contracts designated as net investment hedges during the year ended December 31, 2018. There were no taxes attributed to foreign currency contracts during the years ended December 31, 2019 and 2017. Net of $2.0 million and $2.5 million tax expense attributed to commodity contracts during the years ended December 31, 2018, 2017, respectively. There were no taxes attributed to commodity contracts during the year ended December 31, 2019.

(2)No tax expense or benefit was recorded for the year ended December 31, 2019. Net of tax expense of $0.3 million for the year ended December 31, 2018.

(3)No tax expense or benefit was recorded for the year ended December 31, 2019. Net of tax benefit of $0.7 million and $1.1 million attributed to interest rate swaps for the years ended December 31, 2018 and 2017, respectively. Net of tax benefit of $2.4 million and $1.5 million attributed to commodity contracts during the years ended December 31, 2018 and 2017, respectively.

Derivatives Designated as Hedging Instruments

Interest Rate Swaps

The Company has interest rate swap agreements to hedge certain variable rate non-recourse debt. These interest rate swaps qualify for hedge accounting and were 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. The change in the fair value of the components included in the effectiveness assessment of these derivatives is initially reported in AOCI and subsequently reclassified to earnings in the periods when the hedged transactions affect earnings (the payment of interest). The amounts deferred in AOCI and reclassified into earnings during the years ended December 31, 2019, 2018 and 2017 related to these interest rate swaps are provided in the tables above. The loss expected to be reclassified into earnings over the next twelve months is approximately $6.9 million. The maximum term of outstanding interest rate swaps designated as hedging instruments is 19 years.

Foreign Currency Forward Contracts

The Company uses foreign currency forward contracts to hedge portions of its net investment positions in certain subsidiaries with Euro (“€”) and Canadian dollar (“C$”) functional currencies and to manage its foreign exchange risk. For instruments that are designated and qualify as hedges of net investment in foreign operations, the effective portion of the net gains or losses attributable to changes in exchange rates are recorded in foreign currency translation adjustments within AOCI.

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The recognition in earnings of amounts previously recorded in AOCI is limited to circumstances such as complete or substantial liquidation of the net investment in the hedged foreign operation. 

Cash flows from derivative instruments designated as net investment hedges are classified as investing activities in the consolidated statements of cash flows.

As of December 31, 2019, the total notional amount of foreign currency forward contracts designated as net investment hedges was €200 million and C$94 million. The maturity dates of these derivative instruments designated as net investment hedges range from 3 months to 33 months. As of December 31, 2018, the total notional amount of foreign currency forward contracts designated as net investment hedges was €320 million and C$81.6 million. The maturity dates of these derivative instruments designated as net investment hedges range from 3 months to 2 years. There were no foreign currency forward contracts designated as net investment hedges as of December 31, 2017.

Commodity Contracts

The Company has two long-dated physically delivered commodity contracts that hedge variability in cash flows associated with the sales of power from certain wind renewable energy facilities located in Texas. One of these commodity contract qualifies for hedge accounting and is designated as a cash flow hedge. The change in the fair value of the components included in the effectiveness assessment of this derivative is initially reported in AOCI and subsequently reclassified to earnings in the periods when the hedged transactions affect earnings (the sale of electricity). The amounts deferred in AOCI and reclassified into earnings during the years ended December 31, 2019, 2018 and 2017 related to these commodity contracts are provided in the tables above. The gain expected to be reclassified into earnings over the next twelve months is approximately $1.6 million. The maximum term of the outstanding commodity contract designated as a hedging instrument is 8 years.

Derivatives Not Designated as Hedging Instruments

Interest Rate Swaps

The Company has interest rate swap agreements that economically hedge the cash flows for non-recourse debt. These interest rate swaps pay a fixed rate and the counterparties to the agreements pay a variable interest rate. The changes in fair value are recorded in interest expense, net in the consolidated statements of operations as these derivatives are not accounted for under hedge accounting.

Foreign Currency Contracts

The Company has foreign currency forward and option contracts that economically hedge its exposure to foreign currency fluctuations. As these hedges are not accounted for under hedge accounting, the changes in fair value are recorded in loss (gain) on foreign currency exchange, net in the consolidated statements of operations.

Commodity Contracts

The Company has commodity contracts that to economically hedge commodity price variability inherent in certain electricity sales arrangements. If the Company sells electricity to an independent system operator market and there is no PPA available, it may enter into a commodity contract to hedge all or a portion of their estimated revenue stream. These commodity contracts require periodic settlements in which the Company receives a fixed-price based on specified quantities of electricity and pays the counterparty a variable market price based on the same specified quantity of electricity. As these derivatives are not accounted for under hedge accounting, the changes in fair value are recorded in operating revenues, net in the consolidated statements of operations.

13. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair values of assets and liabilities are determined using either unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available and using unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available. The Company uses valuation techniques that maximize the use of observable inputs. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. If the inputs into the valuation are not corroborated by market data, in such instances, the valuation for these contracts is established using techniques including the extrapolation from or interpolation between actively traded contracts, as well as the calculation of implied volatilities. When such inputs have a

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significant impact on the measurement of fair value, the instrument is categorized as Level 3. The Company regularly evaluates and validates the inputs used to determine the fair value of Level 3 contracts by using pricing services to support the underlying market price of the commodity.

The Company uses a discounted cash flow valuation technique to determine the fair value of its derivative assets and liabilities. The primary inputs in the valuation models for commodity contracts are market observable forward commodity curves, risk-free discount rates, volatilities and, to a lesser degree, credit spreads. The primary inputs into the valuation of interest rate swaps and foreign currency contracts are forward interest rates and foreign currency exchange rates and, to a lesser degree, credit spreads.

Recurring Fair Value Measurements

The following table summarizes the financial instruments measured at fair value on a recurring basis classified in the fair value hierarchy (Level 1, 2 or 3) based on the inputs used for valuation in the consolidated balance sheets:

	As of December 31, 2019								As of December 31, 2018
(In thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	809	$	—	$	809	$	—	$	7,296	$	—	$	7,296
Commodity contracts	—		5,859		59,312		65,171		—		12,952		79,652		92,604
Foreign currency contracts	—		7,556		—		7,556		—		5,455		—		5,455
Total derivative assets	$	—	$	14,224	$	59,312	$	73,536	$	—	$	25,703	$	79,652	$	105,355
Liabilities
Interest rate swaps	$	—	$	134,986	$	—	$	134,986	$	—	$	126,100	$	—	$	126,100
Foreign currency contracts	—		377		—		377		—		3,307		—		3,307
Total derivative liabilities	$	—	$	135,363	$	—	$	135,363	$	—	$	129,407	$	—	$	129,407

The Company’s interest rate swaps, foreign currency contracts and financial commodity contracts are considered Level 2, since all significant inputs are corroborated by market observable data. The Company’s long-term physically settled commodity contracts (see Note 12. Derivatives) are considered Level 3 as they contain significant unobservable inputs. There were no transfers in or out of Level 1, Level 2 and Level 3 during the years ended December 31, 2019 and 2018.

The following table reconciles the changes in the fair value of derivative instruments classified as Level 3 in the fair value hierarchy for the years ended December 31, 2019 and 2018:

	Year Ended December 31,
(In thousands)	2019		2018
Balance as of January 1	$	79,652	$	80,268
Realized and unrealized (losses) gains:
Included in other comprehensive loss	(8,920)		(4,736)
Included in operating revenues, net	(12,441)		6,244
Net settlements	1,021		(2,124)
Balance as of December 31	$	59,312	$	79,652

The significant unobservable inputs used in the valuation of the Company’s commodity contracts classified as Level 3 in the fair value hierarchy as of December 31, 2019 are as follows:

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(In thousands, except range)	Fair Value as of December 31, 2019
Transaction Type	Assets		Liabilities		Valuation Technique	Unobservable Inputs as of December 31, 2019
Commodity contracts - power	$	59,312	$	—	Option model	Volatilities	14.2%
							Range
					Discounted cash flow	Forward price (per MWh)	$	6.30	-	$	169.30

The sensitivity of the Company’s fair value measurements to increases (decreases) in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Impact on Fair Value Measurement
Increase (decrease) in forward price	Forward sale	Decrease (increase)
Increase (decrease) in implied volatilities	Purchase option	Increase (decrease)

The Company measures the sensitivity of the fair value of its Level 3 commodity contracts to potential changes in commodity prices using a mark-to-market analysis based on the current forward commodity prices and estimates of the price volatility. An increase in power forward prices will produce a mark-to-market loss, while a decrease in prices will result in a mark-to-market gain. An increase in the estimates of the price volatility will produce a mark-to-market gain, while a decrease in volatility will result in a mark-to-market loss.

Fair Value of Debt

The carrying amount and estimated fair value of the Company’s long-term debt as of December 31, 2019 and 2018 was as follows:

	As of December 31, 2019				As of December 31, 2018
(In thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	6,235,382	$	6,512,188	$	5,761,845	$	5,789,702

The fair value of the Company’s long-term debt, except the corporate-level senior notes, was determined using inputs classified as Level 2 and a discounted cash flow approach using market rates for similar debt instruments. The fair value of the corporate-level senior notes is based on market price information which is classified as a Level 1 input. They are measured using the last available trades at the end of each respective fiscal year. The fair values of the Senior Notes due 2023, Senior Notes due 2028 and Senior Notes due 2030 were 103.4%, 105.8% and 102.2% of face value as of December 31, 2019, respectively. The fair values of the Senior Notes due 2023, Senior Notes due 2025 and Senior Notes due 2028 were 93.5%, 89.8% and 102.5% of face value as of December 31, 2018, respectively.

Nonrecurring Fair Value Measurements

Assets and liabilities that are measured at fair value on a nonrecurring basis relate primarily to renewable energy facilities, goodwill and intangibles, which are remeasured when the derived fair value is below the carrying value on the Company’s consolidated balance sheet. For these assets, the Company does not periodically adjust carrying value to fair value except in the event of impairment. When the impairment has occurred, the Company measures the required charges and adjusts the carrying value as discussed in Note 2. Summary of Significant Accounting Policies. For discussion about the impairment testing of assets and liabilities not measured at fair value on a recurring basis see Note 6. Renewable Energy Facilities and Note 7. Intangible Assets, Net and Goodwill for additional details.

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14. OTHER FINANCIAL INFORMATION

Other current assets presented in the consolidated balance sheets consisted of the following:

	As of December 31,
(In thousands)	2019		2018
Taxes receivable	$	14,435	$	18,798
Indemnity receivable	15,229		15,348
Spare parts inventory	266		7,562
Purchased solar renewable energy credits	5,019		—
Due from financial institutions	6,299		—
Due from service provider	8,212		—
Note receivable from public utility company	4,187		1,027
Miscellaneous	4,035		9,298
Total other current assets	$	57,682	$	52,033

Other liabilities presented in the consolidated balance sheets consisted of the following:

	As of December 31,
(In thousands)	2019		2018
Energy tracking accounts payable	$	71,277	$	38,993
Intangible liabilities	15,864		18,883
Deferred revenue	9,388		12,090
Due to service provider	4,484		4,587
Miscellaneous	11,059		16,235
Total other non-current liabilities	$	112,072	$	90,788

15. VARIABLE INTEREST ENTITIES

The Company assesses entities for consolidation in accordance with ASC 810. The Company consolidates VIEs in renewable energy facilities when the Company is determined to be the primary beneficiary. VIEs are entities that lack one or more of the characteristics of a VOE. The Company has a controlling financial interest in a VIE when its variable interest(s) provide it with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The VIEs own and operate renewable energy facilities in order to generate contracted cash flows. The VIEs were funded through a combination of equity contributions from the owners and non-recourse project-level debt.

The carrying amounts and classification of the consolidated assets and liabilities of the VIEs included in the Company’s consolidated balance sheets were as follows:

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	As of December 31,
(In thousands)	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	44,083	$	69,896
Restricted cash	10,562		10,428
Accounts receivable, net	39,804		31,740
Derivative assets, current	2,461		2,038
Prepaid expenses	3,466		3,194
Other current assets	21,228		16,761
Total current assets	121,604		134,057
Renewable energy facilities, net	3,188,508		3,064,675
Intangible assets, net	690,594		751,377
Restricted Cash	4,454		12,140
Derivative assets	56,852		78,916
Other assets	7,061		2,441
Total assets	$	4,069,073	$	4,043,606
Liabilities
Current liabilities:
Current portion of long-term debt and financing lease obligations	$	55,089	$	64,251
Accounts payable, accrued expenses and other current liabilities	42,685		55,996
Derivative liabilities, current	449		543
Total current liabilities	98,223		120,790
Long-term debt and financing lease obligations, less current portion	932,862		885,760
Operating lease obligations, less current portion	138,816		—
Asset retirement obligations	116,159		86,457
Derivative liabilities	894		3,558
Other liabilities	41,813		39,014
Total liabilities	$	1,328,767	$	1,135,579

The amounts shown in the table above exclude intercompany balances that are eliminated upon consolidation. All the assets in the table above are restricted for settlement of the VIE obligations, and all the liabilities in the table above can only be settled by using VIE resources.

16. STOCKHOLDERS’ EQUITY

TerraForm Power, Inc. has 100,000,000 authorized shares of preferred stock of par value $0.01 per share, and 1,200,000,000 authorized shares of Common Stock of par value $0.01 per share. There are no other authorized classes of shares and the Company does not have any issued shares of preferred stock. As of December 31, 2019, the combined ownership of affiliates of Brookfield was approximately 62%.

On January 11, 2020, the Company received an unsolicited, non-binding proposal (the “Brookfield Proposal”) from Brookfield Renewable, an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% already held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board of Directors of the Company (the “Board”) consisting solely of independent Directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a special committee (the “Special Committee”) of non-executive, disinterested and independent Directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the

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Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. On March 16, 2020, on the unanimous recommendation of the Special Committee and with the approval of the Board, the Company and Brookfield Renewable and certain of their affiliates entered into a definitive agreement (the “Reorganization Agreement”) for Brookfield Renewable to, among other things, acquire all of the shares of Common Stock, other than the 62% currently owned by Brookfield Renewable and its affiliates (the transactions contemplated by the Reorganization Agreement, the “Transactions”). Upon the consummation of the Transactions, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions, will be converted into the right to receive, at each TerraForm Power shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. As provided by the Brookfield Proposal, the adoption of the Plan of Merger (as defined in the Reorganization Agreement) and the approval of the Reorganization Agreement and the consummation of the transactions contemplated thereby is subject to the non-waivable approval of TerraForm Power’s shareholders representing a majority of the outstanding shares of Common Stock not owned by Brookfield Renewable and its affiliates and the consummation of the transactions contemplated by the Reorganization Agreement are subject to customary closing conditions, including receipt of certain regulatory approval. As of the date of this Annual Report, Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

The following table reflects the changes in the Company’s shares of Common Stock outstanding during the years ended December 31, 2019 and 2018:

	As of December 31,
(In thousands)	2019		2018
Balance as of January 1	$	209,142	$	148,086
Issuance of Common Stock in public offering1	14,907		—
Issuance of Common Stock to affiliate2,3	2,982		61,056
Net shares issued under equity incentive plan	13		—
Less: Repurchases of Common Stock4	(543)		—
Balance as of December 31	$	226,501	$	209,142

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(1)On October 8, 2019, the Company completed an underwritten registered public offering of 14,907,573 shares of Common Stock at a price of $16.77 per share for a total consideration of $250.0 million, not including transaction costs.

(2)On October 8, 2019, concurrently with the public offering described above, the Company completed a private placement of 2,981,514 shares of Common Stock at a price of $16.77 per share to an affiliate of Brookfield for a total consideration of $50.0 million, not including transaction costs.

(3)On June 11, 2018, the Company completed a private placement of 60,975,609 shares of the Company’s Common Stock with affiliates of Brookfield at a price of $10.66 per share for a total consideration of $650.0 million. The proceeds of the offering were used to pay a portion of the purchase price of the Tendered Shares of Saeta. On August 3, 2018, the Company issued 80,084 shares of Common Stock to an affiliate of Brookfield in connection with the net losses incurred, such as out-of-pocket losses, damages, costs, fees and expenses, in connection with the obtainment of a final resolution of a certain litigation matter.

(4)During the fourth quarter of 2019, the Company repurchased a total of 543,265 shares of Common Stock at a total cost of $8.4 million and recorded within Treasury Stock on the consolidated balance sheets.

Merger Consummation and SunEdison Settlement Agreement

As discussed in Note 1. Nature of Operations and Organization, on October 16, 2017, pursuant to the Merger Agreement, Merger Sub merged with and into TerraForm Power, with TerraForm Power continuing as the surviving corporation in the Merger. Immediately following the consummation of the Merger, there were 148,086,027 Class A shares of TerraForm Power outstanding, which excludes 138,402 Class A shares that were issued and held in treasury to pay applicable employee tax withholdings for RSUs held by employees that vested upon the consummation of the Merger. As a result of the Merger, Orion Holdings acquired 51% of TerraForm Power’s outstanding Class A shares.

Prior to the consummation of the Merger, SunEdison was the indirect holder of 100% of the shares of Class B common stock of TerraForm Power and held approximately 83.9% of the combined total voting power of the holders of TerraForm Power’s Class A Common Stock and Class B common stock. As contemplated by the Merger Agreement and in satisfaction of its obligations under the Settlement Agreement, SunEdison exchanged, effective immediately prior to the effective time of the Merger, all of the Class B units of Terra LLC held by it or any of its controlled affiliates for 48,202,310 Class A shares of TerraForm Power. Following completion of this exchange, all of the issued and outstanding shares of Class B common stock of TerraForm Power were automatically redeemed and retired. Pursuant to the Settlement Agreement, immediately following this exchange, the Company issued to SunEdison additional Class A shares such that immediately prior

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to the effective time of the Merger, SunEdison and certain of its affiliates held an aggregate number of Class A shares equal to 36.9% of TerraForm Power’s fully diluted share count (which was subject to proration based on the Merger consideration election results as discussed below). As a result of the Merger closing, TerraForm Power is no longer a controlled affiliate of SunEdison and is now a controlled affiliate of Brookfield.

At the effective time of the Merger, each share of Common Stock of TerraForm Power issued and outstanding immediately prior to the effective time of the Merger, except for certain excluded shares, was converted into the right to, at the holder’s election and subject to proration as described below, either (i) receive $9.52 per Class A Share, in cash, without interest (the “Per Share Cash Consideration”) or (ii) retain one share of Common Stock, par value $0.01 per share, of the surviving corporation (the “Per Share Stock Consideration,” and, together with the Per Share Cash Consideration, without duplication, the “Per Share Merger Consideration”). Issued and outstanding shares included shares issued in connection with the SunEdison Settlement Agreement as more fully described above and shares underlying outstanding RSUs of the Company under the Company’s 2014 Second Amended and Restated Long-Term Incentive Plan (the “2014 LTIP”). At the effective time of the Merger, any vesting conditions applicable to any Company RSU outstanding immediately prior to the effective time of the Merger under the 2014 LTIP were automatically and without any required action on the part of the holder, deemed to be satisfied in full, and such Company RSU was canceled and converted into the right to receive the Per Share Merger Consideration, including the election of the Per Share Stock Consideration or the Per Share Cash Consideration in respect of each share (in the case of RSUs subject to performance conditions, with such conditions deemed satisfied at “target” levels), less any tax withholdings. The Per Share Stock Consideration was subject to proration in the event that the aggregate number of Class A Shares for which an election to receive the Per Share Stock Consideration exceeded 49% of the TerraForm Power fully diluted share count (the “Maximum Stock Consideration Shares”). Additionally, the Per Share Cash Consideration was subject to proration in the event that the aggregate number of Class A shares for which an election to receive the Per Share Cash Consideration exceeded the TerraForm Power fully diluted share count minus (i) the Maximum Stock Consideration Shares, (ii) any Class A shares currently held by affiliates of Brookfield, and (iii) any shares for which the holders seek appraisal under Delaware law. Based on the results of the consideration election, the elections of the Per Share Stock Consideration were oversubscribed and the proration ratio was 62.6%, which meant that stockholders electing to receive 100% of their merger consideration in stock retained 62.6% of their Class A shares in the Merger and received cash consideration in respect of 37.4% of their shares.

On October 16, 2017, in connection with the consummation of the Merger, the Company entered into a registration rights agreement (the “SunEdison Registration Rights Agreement”) with SunEdison, SunEdison Holdings Corporation (“SHC”) and SUNE ML 1, LLC (“SML1”). The SunEdison Registration Rights Agreement governed the rights of SunEdison, SHC, SML1 and certain permitted assigns with respect to the registration for resale of Class A shares held by them immediately following the Merger. The Company registered these shares in December of 2017, and these shares were distributed by SunEdison, Inc., SHC and SML1 to certain creditors under the plan of reorganization in connection with SunEdison’s emergence from bankruptcy in December of 2017. 

Upon the consummation of the Merger, TerraForm Power’s certificate of incorporation was amended and restated to include 100,000,000 authorized shares of preferred stock, par value $0.01 per share, and 1,200,000,000 authorized shares of Common Stock, par value $0.01 per share. There were no other authorized classes of shares, and the Company did not have any issued shares of preferred stock as of December 31, 2019, 2018 and 2017.

2019 Public Offering and Concurrent Private Placement of Common Stock to an Affiliate

On October 8, 2019, the Company completed an underwritten registered public offering of 14,907,573 shares of Common Stock at a price of $16.77 per share (the “Public Offering”), for a total consideration of $250.0 million, not including transaction costs. In connection with the Public Offering, the Company entered into an underwriting agreement, dated October 3, 2019 among the Company, Terra LLC and RBC Capital Markets, LLC, as the underwriter.

Concurrent with the Public Offering, on October 8, 2019, the Company completed a private placement of 2,981,514 shares of Common Stock at a price of $16.77 per share (the “2019 Private Placement”), to BBHC Orion Holdco L.P., an affiliate of Brookfield (the “2019 Private Placement Purchaser”), for a total consideration of $50.0 million, not including transaction costs. No underwriting discounts or commissions were paid with respect to the 2019 Private Placement. In connection with the 2019 Private Placement, the Company entered into a stock purchase agreement, dated October 8, 2019, with the 2019 Private Placement Purchaser. The Common Stock issued in the 2019 Private Placement were not registered with the SEC, in reliance on Section 4(a)(2) of the Securities Act and the acknowledgment of the 2018 Private Placement Purchaser that it is an “accredited investor” within the meaning of Rule 501(a) of Regulation D of the Securities Act or a “qualified institutional buyer” under Rule 144A of the Securities Act. Following the Public Offering and the 2019 Private Placement, as of December 31, 2019, affiliates of Brookfield held approximately 62% of the Company’s Common Stock.

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The proceeds of the Public Offering and 2019 Private Placement were used to repay the amounts due under the Revolver and for general corporate purposes.

2018 Private Placement of Common Stock to Affiliates

On June 11, 2018, the Company completed a private placement of 60,975,609 shares of Common Stock at a price of $10.66 per share (the “2018 Private Placement”), to Orion Holdings and BBHC Orion Holdco L.P. (together, the “2018 Private Placement Purchasers”) for a total consideration of approximately $650.0 million, not including transaction costs. No underwriting discounts or commissions were paid with respect to the 2018 Private Placement. In connection with the 2018 Private Placement, the Company entered into a stock purchase agreement, dated June 11, 2018, with the 2018 Private Placement Purchasers. The Common Stock issued in the 2018 Private Placement were not registered with the SEC, in reliance on Section 4(a)(2) of the Securities Act and the acknowledgment of each of the 2018 Private Placement Purchasers that it is an “accredited investor” within the meaning of Rule 501(a) of Regulation D of the Securities Act or a “qualified institutional buyer” under Rule 144A of the Securities Act. Immediately upon completion of the 2018 Private Placement, affiliates of Brookfield held approximately 65% of TerraForm Power’s Common Stock as of the date thereof.

The proceeds of the 2018 Private Placement were used by the Company to pay a portion of the purchase price of the Tendered Shares of Saeta. The purchase of $650 million of TerraForm Power’s Common Stock by the 2018 Private Placement Purchasers was made pursuant to a support agreement that the Company had entered into with Brookfield, dated February 6, 2018, and amended on May 28, 2018, at the previously agreed backstop price of $10.66 per share.

2018 Issuance of Common Stock upon Final Resolution of Chamblee Class Action

On August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Common Stock to Orion Holdings in connection with the net losses incurred as a result of the final resolution of a securities class action under federal securities laws (the “Chamblee Class Action”). The net losses for the Chamblee Class Action include the $1.1 million contributed by the Company to the settlement but do not include the $13.6 million contributed by the Company’s insurers and certain attorneys’ fees that TerraForm Global reimbursed to the Company pursuant to the insurance allocation arrangements entered into with the Company in 2017.

Cash Distributions

The following table presents the cash distributions declared and/or paid on Common Stock during the years ended December 31, 2019, 2018 and 2017:

	Type	Distributions per Share		Declaration Date	Record Date	Payment Date
2019:
First Quarter	Ordinary	$	0.2014	March 13, 2019	March 24, 2019	March 29, 2019
Second Quarter	Ordinary	0.2014		May 8, 2019	June 3, 2019	June 17, 2019
Third Quarter	Ordinary	0.2014		August 8, 2019	September 3, 2019	September 17, 2019
Fourth Quarter	Ordinary	0.2014		November 6, 2019	December 2, 2019	December 16, 2019
2018:
First Quarter	Ordinary	$	0.19	February 6, 2018	February 28, 2018	March 30, 2018
Second Quarter	Ordinary	0.19		April 30, 2018	June 1, 2018	June 15, 2018
Third Quarter	Ordinary	0.19		August 13, 2018	September 1, 2018	September 15, 2018
Fourth Quarter	Ordinary	0.19		November 8, 2018	December 3, 2018	December 17, 2018
2017:
Fourth Quarter	Special1	1.94		October 6, 2017	October 16, 2017	October 17, 2017

———

(1)On October 6, 2017, the Board declared the payment of a special cash distribution to holders of record immediately prior to the effective time of the Merger in the amount of $1.94 per fully diluted share, which included the Company’s issued and outstanding Class A shares, Class A shares issued to SunEdison pursuant to the Settlement Agreement (more fully described above) and Class A shares underlying outstanding RSUs of the Company under the 2014 LTIP.

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Share Repurchase Program

On July 25, 2019, the Board of the Company authorized the renewal of the Company’s share repurchase program through August 4, 2020. Under the share repurchase program, the Company may repurchase up to 5% of the Company’s Common Stock outstanding as of July 25, 2019. The timing and the amount of any repurchases of Common Stock will be determined by the Company’s management based on its evaluation of market conditions and other factors. Repurchases of Common Stock may be made under a Rule 10b5-1 plan, which would permit Common Stock to be repurchased when the Company might otherwise be precluded from doing so under insider trading laws, open market purchases, privately-negotiated transactions, block purchases or otherwise in accordance with applicable federal securities laws, including Rule 10b-18 under the Exchange Act. The program may be suspended or discontinued at any time and does not obligate the Company to purchase any minimum number of stock. Any repurchased Common Stock will be held by the Company as treasury shares. The Company expects to fund any repurchases from the available liquidity.

During the fourth quarter of 2019, the Company repurchased 543,265 shares at a total cost of $8.4 million and recorded within Treasury Stock on the consolidated balance sheets. No shares were repurchased by the Company during the year ended December 31, 2018.

17. STOCK-BASED COMPENSATION

In March 2018, the Company implemented its 2018 Amended and Restated Long-Term Incentive Plan (the “2018 LTIP”), which is an equity incentive plan that provides for the award of incentive and nonqualified stock options, restricted stock awards (“RSAs”) and RSUs to employees and directors of the Company. The 2018 LTIP amended and restated the 2014 LTIP. During the years ended December 31, 2017 and 2016, the 2014 LTIP extended to employees and directors who also provided services to the Company’s affiliates, including SunEdison and TerraForm Global during the periods those companies were affiliates of the Company. The 2018 LTIP only applies to employees and directors of the Company. The maximum contractual term of an award is ten years from the date of grant. As of December 31, 2019, an aggregate of 3,734,185 shares of Common Stock were available for issuance under the 2018 LTIP. Upon exercise of stock options or the vesting of RSUs, the Company will issue shares that have been previously authorized to be issued.

Historically, stock-based compensation costs related to equity awards in the Company’s stock were allocated to the Company, SunEdison and TerraForm Global based on the relative percentage of time that the personnel and directors spent providing services to the respective companies. As of January 1, 2017, the Company hired certain former employees of SunEdison who provided dedicated services to the Company. The amount of stock-based compensation expense related to equity awards in the Company’s stock which has been awarded to the Company’s employees was $11.3 million for the years ended December 31, 2017, and is reflected in the consolidated statements of operations within general and administrative expenses. The total amount of stock-based compensation cost related to equity awards in the Company’s stock which has been allocated to SunEdison and TerraForm Global was $3.4 million for the year ended December 31, 2017, and was recognized as a distribution to SunEdison within Net SunEdison investment on the consolidated statements of stockholders’ equity with no impact to the Company’s consolidated statements of operations. Similarly, stock-based compensation costs related to equity awards in the stock of SunEdison and TerraForm Global awarded to employees of the Company were allocated to the Company. The amount of stock-based compensation expense related to equity awards in the stock of SunEdison and TerraForm Global that was allocated to the Company was $5.5 million for the year ended December 31, 2017, and is reflected in the consolidated statements of operations within general and administrative expenses - affiliate and has been treated as an equity contribution from SunEdison within Net SunEdison investment on the consolidated statements of stockholders’ equity. In July of 2017, the Bankruptcy Court approved SunEdison’s plan of reorganization which provided that all unvested equity awards in the stock of SunEdison would be canceled. As a result, all previously unrecognized compensation cost pertaining to unvested equity awards in the stock of SunEdison that were held by the Company’s employees of $2.2 million was allocated to the Company, which is reflected within the stock-based compensation expense amount for the year ended December 31, 2017.

Restricted Stock Awards

RSAs provide the holder with immediate voting rights, but are restricted in all other respects until vested. Upon a termination of employment for any reason, any unvested shares of Common Stock held by the terminated participant will be forfeited. All unvested RSAs are paid and distributions. There were no unvested RSAs as of December 31, 2017 and 2018.

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The following table presents information regarding outstanding RSAs as of December 31, 2019, 2018 and 2017. and changes during the year then ended:

	Number of RSAs Outstanding	Weighted-Average Grant-Date Fair Value Per Share		Aggregate Intrinsic Value (in millions)
Balance at January 1, 2017	366,195	$	8.51
Vested	(366,195)	8.51
Balance as of December 31, 2017, 2018 and 2019	—	—		$	—

Restricted Stock Units

The RSUs do not entitle the holders to voting rights and holders of the RSUs do not have any right to receive cash distributions. The following table presents information regarding outstanding RSUs as of December 31, 2019 and 2018 and changes during the year then ended:

(In thousands, except per share data and the number of years)	Number of RSUs Outstanding	Weighted- Average Exercise Price		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Life
Balance at January 1, 2017	1,622,953
Granted	523,877
Vested	(1,414,857)
Forfeited	(731,973)
Balance as of December 31, 2017	—
Granted	117,424
Forfeited	(14,124)
Balance as of December 31, 2018	103,300	$	11.15	$	1,159	2 years
Granted	156,550	12.17
Vested	(20,878)	11.15
Forfeited	(47,036)	11.64
Balance as of December 31, 2019	191,936	11.57		2,954		1 year

The total fair value of RSUs that vested during the years ended December 31, 2019, and 2017, was $0.3 million and $16.7 million, respectively. The weighted average fair value of RSUs on the date of grant during the same periods was $12.17 and $12.22, respectively. No RSUs vested during the year ended December 31, 2018 and the weighted-average fair value on the date of the grant was $11.15 per share. The unrecognized compensation cost related to the RSUs as of December 31, 2019 and 2018, was $1.6 million and $0.9 million, respectively. The vesting schedule of the RSUs awarded in 2019 and 2018 is three years and the Company recognizes the grant-date fair value as a compensation cost on a straight-line basis over the vesting period.

As discussed in Note 1. Nature of Operations and Organization, on October 16, 2017, TerraForm Power consummated the Merger with certain affiliates of Brookfield. Pursuant to the 2014 LTIP, the Merger resulted in a change of control causing all unvested equity awards issued under the plan to vest. As a result, the Company recognized a $7.0 million stock-based compensation charge in the fourth quarter of 2017, which is reflected in the consolidated statements of operations within general and administrative expenses. The Company also recognized a $1.0 million charge related to allocated stock-based compensation costs for equity awards in the stock of TerraForm Global that vested upon the change of control of TerraForm Power. The charge is reflected in the consolidated statements of operations within general and administrative expenses - affiliate.

Time-based RSUs

During the year ended December 31, 2017, the Company awarded 523,877 time-based RSUs to certain employees and executive officers of SunEdison, TerraForm Global and the Company. The weighted average grant-date fair value of these time-based awards during the same periods was $6.4 million which was calculated based on the Company’s closing stock price on

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the date of the grant. The vesting schedule of the awarded RSUs ranged from six months to four years, and the Company was recognizing the grant-date fair value as compensation cost on a straight-line basis over the vesting period. These time-based RSUs vested upon the consummation of the Merger. During the year ended December 31, 2019 and 2018, the Company did not award any time-based RSUs.

Stock Options

As of December 31, 2019 and 2018, there were no outstanding stock options and no unrecognized compensation cost in relation to stock options.

18. NON-CONTROLLING INTERESTS

Non-controlling Interests

Non-controlling interests represent the portion of net assets in consolidated entities that are not owned by the Company in renewable energy facilities.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act, which enacted major changes to the U.S. tax code, including a reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Since the 21% rate enacted in December 2017 went into effect on January 1, 2018, the HLBV methodology utilized by the Company to determine the value of its non-controlling interests began to use the new rate on that date. The HLBV method is a point in time estimate that utilizes inputs and assumptions in effect at each balance sheet date based on the liquidation provisions of the respective operating partnership agreements. For the year ended December 31, 2018, $151.2 million of the decline in the non-controlling interests balance and a corresponding allocation of net loss attributable to non-controlling interests was driven by this reduction in the tax rate used in the HLBV methodology used by the Company. In the calculation of the carrying values through HLBV, the Company allocated significantly lower amounts to certain non-controlling interests (i.e., tax equity investors) in order to achieve their contracted after-tax rate of return as a result of the reduction of the federal income tax rate from 35% to 21% as specified in the Tax Act.

Redeemable Non-controlling Interests

Non-controlling interests in subsidiaries that are redeemable either at the option of the holder or at fixed and determinable prices at certain dates are classified as redeemable non-controlling interests in subsidiaries between liabilities and stockholders’ equity in the consolidated balance sheets. The redeemable non-controlling interests in subsidiaries balance is determined using the hypothetical liquidation at book value method for the VIE funds or allocation of share of income or losses in other subsidiaries subsequent to initial recognition; however, the non-controlling interests balance cannot be less than the estimated redemption value.

The following table presents the activity of the redeemable non-controlling interests balance for the years ended December 31, 2019, 2018 and 2017:

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(In thousands)	Redeemable Non-controlling Interests
Balance as of December 31, 2016	$	165,975
Distributions	(7,818)
Accretion	6,729
Net income	1,596
Reclassification of Invenergy Wind Interest to non-controlling interests1	(131,822)
Balance as of December 31, 2017	34,660
Cumulative-effect adjustment2	(4,485)
Distributions	(2,458)
Consolidation of redeemable non-controlling interests in acquired renewable energy facilities	55,117
Repurchases of redeemable non-controlling interests, net	(58,014)
Net income	9,209
Exchange differences	(534)
Balance as of December 31, 2018	33,495
Distributions	(1,220)
Repurchases of redeemable non-controlling interests, net3	(4,753)
Non-cash redemption of redeemable non-controlling interests	7,345
Net loss	(11,983)
Balance as of December 31, 2019	$	22,884

———

(1) During the year ended December 31, 2017, the Company recorded $6.7 million adjustment to the value of the Invenergy Wind redeemable non-controlling interest, representing the excess of the future redemption value over its carrying amount based on the SEC guidance in ASC 480-10-S99-3A. Historically, the Company was accreting the redemption value of the Invenergy Wind redeemable non-controlling interest over the redemption period using the straight-line method and accretion adjustments were recorded against additional paid-in capital. As part of the Settlement Agreement, the Option Agreement between Terra LLC and Sun Edison LLC with respect to Invenergy Wind’s remaining 9.9% interest in certain subsidiaries of the Company was rejected upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017. As a result, the Company is no longer obligated to perform on its Option Agreement, and as of October 16, 2017, the Invenergy Wind non-controlling interest amount of $131.8 million was no longer considered redeemable and was reclassified to non-controlling interests as of such date. The redemption adjustments recorded in additional paid-in capital will remain in additional paid-in capital.

(2)See discussion in Note 2. Summary of Significant Accounting Policies regarding the Company’s adoption of ASU No. 2014-09 and ASU No. 2016-08 as of January 1, 2018.

(3)During the year-ended December 31, 2019, the Company purchased the tax equity investors’ interests in certain distributed generation projects in the United States for a combined consideration of $3.9 million, which resulted in increasing the Company’s ownership interest in the related projects to 100%. The difference between the consideration paid and the carrying amounts of the non-controlling interests was recorded as an adjustment to additional paid-in capital within Purchase of (redeemable) non-controlling interests in the consolidated statement of stockholders’ equity.

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19. ACCUMULATED OTHER COMPREHENSIVE INCOME

The following table presents the changes in each component of accumulated other comprehensive (loss) income, net of tax:

(In thousands)	Foreign Currency Translation Adjustments		Hedging Activities1		Accumulated Other Comprehensive Income
Balance as of December 31, 2016	$	(22,133)	$	45,045	$	22,912
Net unrealized gain arising during the period (net of tax expense of $3,238 and $2,428, respectively)	10,300		17,612		27,912
Reclassification of net realized loss (gain) into earnings (net of tax benefit of $8,858 and tax expense of $443, respectively)2	14,741		(2,247)		12,494
Other comprehensive income	25,041		15,365		40,406
Accumulated other comprehensive income	2,908		60,410		63,318
Less: Other comprehensive income attributable to non-controlling interests	8,665		5,992		14,657
Plus: Reallocation from non-controlling interests as a result of SunEdison exchange3	(7,655)		7,012		(643)
Balance as of December 31, 2017	(13,412)		61,430		48,018
Cumulative-effect adjustment (net of tax expense of $1,579)4	—		(4,164)		(4,164)
Cumulative-effect adjustment (net of tax expense of $9,357)5	14,524		(5,156)		9,368
Net unrealized (loss) gain arising during the year (net of tax expense of $3,891 and $3,729, respectively)	(9,517)		1,166		(8,351)
Reclassification of net realized gain into earnings (net of zero and $4,938 tax benefit, respectively)	—		(5,410)		(5,410)
Other comprehensive income	(9,517)		(4,244)		(13,761)
Accumulated other comprehensive income	(8,405)		47,866		39,461
Less: Other comprehensive income attributable to non-controlling interests	—		(777)		(777)
Balance as of December 31, 2018	(8,405)		48,643		40,238
Net unrealized gain (loss) arising during the period (net of zero and $978 tax benefit, respectively)	15,652		(42,290)		(26,638)
Reclassification of net realized gain into earnings (net of zero tax impact)	—		(2,579)		(2,579)
Other comprehensive income (loss)	15,652		(44,869)		(29,217)
Accumulated other comprehensive income	7,247		3,774		11,021
Less: Other comprehensive income attributable to non-controlling interests	—		(624)		(624)
Balance as of December 31, 2019	$	7,247	$	4,398	$	11,645

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(1)See Note 12. Derivatives for additional breakout of hedging gains and losses for interest rate swaps and commodity contracts in a cash flow hedge relationship and the foreign currency contracts designated as hedges of net investments.

(2)The foreign currency translation adjustment amount represents the reclassification of the accumulated foreign currency translation loss for the U.K. Portfolio, as the Company’s sale of this portfolio closed in the second quarter of 2017. The pre-tax amount of $23.6 million was recognized within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

(3)Represents reclassification of accumulated comprehensive (losses) income previously attributed to SunEdison’s non-controlling interest in Terra LLC from non-controlling interests to AOCI as of October 16, 2017, as a result of SunEdison’s exchange of its Class B units in Terra LLC for Class A shares of TerraForm Power as discussed in Note 18. Non-Controlling Interests.

(4)Represents the cumulative-effect adjustment related to the early adoption of ASU 2017-12. See Note 2. Summary of Significant Accounting Policies for additional details.

(5)Represents the cumulative-effect adjustment of deferred taxes stranded in AOCI resulting from the early adoption of ASU No. 2018-02 See Note 2. Summary of Significant Accounting Policies.

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20. COMMITMENTS AND CONTINGENCIES

Letters of Credit

The Company’s customers, vendors and regulatory agencies often require the Company to post letters of credit in order to guarantee performance under certain contracts and agreements. The Company is also required to post letters of credit to secure obligations under various swap agreements and leases and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. The amount that can be drawn under some of these letters of credit may be increased from time to time subject to the satisfaction of certain conditions. As of December 31, 2019, the Company had outstanding letters of credit drawn under the Revolver of $115.5 million and outstanding project-level letters of credit of $266.9 million, drawn under certain project-level financing agreements, respectively, compared to $99.5 million and $197.7 million as of December 31, 2018, respectively.

Guaranty Agreements

The Company and its subsidiaries have entered into guaranty agreements to certain of their institutional tax equity investors and financing parties in connection with their tax equity financing transactions. These agreements do not guarantee the returns targeted by the tax equity investors or financing parties, but rather support any potential indemnity payments payable under the tax equity agreements, including related to management of tax partnerships and recapture of tax credits or renewable energy grants in connection with transfers of the Company’s direct or indirect ownership interests in the tax partnerships to entities that are not qualified to receive those tax benefits.

The Company and its subsidiaries have also provided guaranties in connection with acquisitions of third-party assets or to support project-level contractual obligations, including renewable energy credit sales agreements. The Company and its subsidiaries have also provided other capped or limited contingent guaranties and other support obligations with respect to certain project-level indebtedness.

The amounts of the above guaranties often are not explicitly stated and the overall maximum amount of the related obligations cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guaranties. The Company believes the probability of payments being demanded under these guaranties is remote and no material amounts have been recognized for the underlying fair value of guaranty obligations.

Operating Leases

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment. See Note 8. Leases for details of the Company’s lease arrangements, including rental expense, and future commitments under operating leases.

Long-Term Service Agreements

On August 10, 2018, the Company executed an 11-year framework agreement with affiliates of General Electric (“GE”) that, among other things, provides for the roll out, subject to receipt of third-party consents, of project level, long-term service agreements (“LTSA”) for turbine operations and maintenance “O&M”, as well as other balance of plant services across the Company’s 1.6 GW North American wind fleet. As of December 31, 2019, 15 of 16 project-level LTSAs were in place. Pursuant to the LTSAs with GE, if a facility generates less than the resource-adjusted amount of guaranteed generation, GE is liable to make a payment to the Company, as liquidated damages, corresponding to the amount of operating revenues lost due to such shortfall, after taking into account certain exclusions. In addition, if a facility generates more than the resource-adjusted amount of guaranteed generation, the Company has an obligation to pay a bonus to GE.

On November 1, 2019, the Company executed a 10-year framework agreement with SMA Solar Technology that, among other things, provides for the roll out, subject to receipt of third-party consents, of project level LTSAs for solar O&M, as well as other balance of plant services across the Company’s North American solar fleet.

Legal Proceedings

The Company is not a party to any material legal proceedings other than various administrative and regulatory proceedings arising in the ordinary course of the Company’s business or as described below. While the Company cannot predict with certainty the ultimate resolution of such proceedings or other claims asserted against the Company, certain of the claims, if adversely concluded, could result in substantial damages or other relief.

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Claim relating to First Wind Acquisition

On May 27, 2016, D.E. Shaw Composite Holdings, L.L.C. and Madison Dearborn Capital Partners IV, L.P., as the representatives of the sellers (the “First Wind Sellers”) filed an amended complaint for declaratory judgment against TerraForm Power and Terra LLC in the Supreme Court of the State of New York alleging breach of contract with respect to the Purchase and Sale Agreement, dated as of November 17, 2014 (the “FW Purchase Agreement”) between, among others, SunEdison, Inc. (“SunEdison”), TerraForm Power, Terra LLC and the First Wind Sellers. The amended complaint alleges that Terra LLC and SunEdison became jointly obligated to make $231.0 million in earn-out payments in respect of certain development assets SunEdison acquired from the First Wind Sellers under the FW Purchase Agreement, when those payments were purportedly accelerated by SunEdison’s bankruptcy and by the resignations of two SunEdison employees. The amended complaint further alleges that TerraForm Power, as guarantor of certain Terra LLC obligations under the FW Purchase Agreement, is liable for this sum. In addition, the plaintiffs have claimed legal costs and expenses and, under applicable New York law, their claim accrues interest at a non-compounding rate of 9% per annum.

The defendants filed a motion to dismiss the amended complaint on July 5, 2016, on the ground that, among other things, SunEdison is a necessary party to this action. On February 6, 2018, the court denied the Company’s motion to dismiss after which document discovery began. In April 2019, Terra LLC filed an amended answer to the amended complaint. The Company cannot predict the impact on this litigation of any information that may become available in discovery. Document discovery and depositions are now substantially completed and new pretrial schedule has been agreed between the parties and approved by the court. Subsequent to year end, on January 24, 2020, the parties filed their respective motions to dismiss and on February 12, 2020, the parties filed their respective opposition briefs. The court’s ruling on the motions to dismiss is expected before the end of 2020.

The Company believes the First Wind Sellers’ allegations are without merit and will contest them vigorously. However, the Company cannot predict with certainty the ultimate resolution of any proceedings brought in connection with such a claim.

Whistleblower Complaint by Francisco Perez Gundin

On May 18, 2016, the Company’s former Director and Chief Operating Officer, Francisco Perez Gundin (“Mr. Perez”), filed a complaint against the Company, TerraForm Global, Inc. (“TerraForm Global”) and certain individuals, with the United States Department of Labor. The complaint alleged that the defendants engaged in a retaliatory termination of Mr. Perez’s employment after he allegedly voiced concerns to SunEdison’s Board of Directors about public representations made by SunEdison officers regarding SunEdison’s liquidity position, and after he allegedly voiced his opposition to transactions that he alleged were self-interested and which he alleged SunEdison forced on the Company. He alleged that the Company participated in SunEdison’s retaliatory termination by constructively terminating his position as Chief Operating Officer of the Company in connection with SunEdison’s constructive termination of his employment. He sought lost wages, bonuses, benefits, and other money that he alleged he would have received if he had not been subjected to the allegedly retaliatory termination. The Company’s Position Statement in response to the complaint was filed in October 2016.

On February 21, 2017, Mr. Perez filed Gundin v. TerraForm Global, Inc. et al. against TerraForm Power, TerraForm Global and certain individuals as defendants in the United States District Court for the District of Maryland, which was subsequently transferred to the U.S. District Court for the Southern District of New York (“SDNY”). The complaint asserted claims for retaliation, breach of the implied covenant of good faith and fair dealing and promissory estoppel based on the same allegation in Mr. Perez’s Department of Labor complaint. On March 8, 2018, Mr. Perez voluntarily dismissed the federal action without prejudice. On December 27, 2018, the proceeding before the Department of Labor was dismissed, which Mr. Perez appealed on January 25, 2019. On August 27, 2019, pursuant to Mr. Perez’s offer to settle the dispute, a definitive settlement agreement was executed between the Company and Mr. Perez. The settlement with Mr. Perez was paid entirely from insurance proceeds.

Whistleblower Complaint by Carlos Domenech Zornoza

On May 10, 2016, the Company’s former Director and Chief Executive Officer, Carlos Domenech Zornoza (“Mr. Domenech”), filed a complaint against the Company, TerraForm Global and certain individuals, with the United States Department of Labor. The complaint alleges that the defendants engaged in a retaliatory termination of Mr. Domenech’s employment on November 20, 2015, after he allegedly voiced concerns to SunEdison’s Board of Directors about public representations made by SunEdison officers regarding SunEdison’s liquidity position, and after he allegedly voiced his opposition to transactions that he alleges were self-interested and which he alleges SunEdison forced on the Company. He alleges that the Company participated in SunEdison’s retaliatory termination by terminating his position as Chief Executive

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Officer of the Company in connection with SunEdison’s termination of his employment. He seeks lost wages, bonuses, benefits, and other money that he alleges that he would have received if he had not been subjected to the allegedly retaliatory termination. The Company’s Position Statement in response to the complaint was filed in October 2016.

On February 21, 2017, Mr. Domenech filed Domenech Zornoza v. TerraForm Global, Inc. et. al against TerraForm Power, TerraForm Global and certain individuals as defendants in the United States District Court for the District of Maryland. The complaint asserted claims for retaliation, breach of the implied covenant of good faith and fair dealing and promissory estoppel based on the same allegations in Mr. Domenech’s Department of Labor complaint. On March 15, 2017, the Company filed notice with the Judicial Panel on Multidistrict Litigation to transfer this action to the SDNY where other cases not involving the Company relating to the SunEdison bankruptcy are being tried. The plaintiff opposed the transfer. However, the transfer was approved by the Judicial Panel on Multidistrict Litigation. On November 6, 2017, TerraForm Power and the other defendants filed a motion to dismiss Mr. Domenech’s complaint, and Mr. Domenech filed a response on December 21, 2017. On March 8, 2018, Mr. Domenech voluntarily dismissed the federal action without prejudice, which would permit the action to be refiled.

On August 16, 2018, Mr. Domenech filed a second complaint with the United States District Court for the District of Maryland, with substantially the same allegations. On October 17, 2018, the Company filed notice with the Judicial Panel on Multidistrict Litigation to transfer this action to the SDNY. The Plaintiff opposed the transfer. However, the transfer was approved by the Judicial Panel on Multidistrict Litigation. On March 15, 2019, the Company, TerraForm Global, and several individual defendants filed a joint motion to dismiss Mr. Domenech’s complaint. Mr. Domenech filed a response on April 15, 2019, and the Company, TerraForm Global, and the individual defendants filed a reply on April 25, 2019. On December 9, 2019, the Court dismissed two of his three claims against the Company and TerraForm Global. On January 22, 2020, the Company filed an answer to Mr. Domenech’s remaining, narrowed claim of retaliatory termination.

The Company reserved for its estimated loss related to this complaint in 2016, which was not considered material to the Company’s consolidated results of operations, and this amount remains accrued as of December 31, 2019. However, the Company is unable to predict with certainty the ultimate resolution of these proceedings.

Derivative Class Action

On September 19, 2019, lead plaintiff Martin Rosson filed a derivative and class action lawsuit in the Delaware Court of Chancery on behalf of the Company, himself, and other minority stockholders of the Company against Brookfield and certain of its affiliates (including the Company as a nominal defendant). The complaint alleges that the defendant controlling stockholders breached their fiduciary duty to minority stockholders because the Company undertook a private placement of the Company’s stock on terms that the complaint alleges are unfair, instead of pursuing a public offering. The proceeds of the private placement were used to fund the acquisition by the Company of Saeta and had been approved by the Conflicts Committee of the Company’s Board of Directors. The complaint seeks the rescission and invalidation of the private placement and payment to the Company of rescissory damages, among other relief. In a related development, on October 15, 2019, the Company received a demand letter for the production of books and records pursuant to 8 Del. C. § 220 to allow counsel to the City of Dearborn Policy and Retirement System (a purported shareholder of the Company) to investigate potential breaches of fiduciary duty by Brookfield and the Company’s Board of Directors in connection with the funding of the acquisition of Saeta. Subsequent to year end, on January 27, 2020, the City of Dearborn Police and Retirement System filed a derivative and class action lawsuit in the Delaware Court of Chancery on behalf of the Company, itself, and other minority stockholders of the Company against Brookfield and certain of its affiliates (including the Company as a nominal defendant) alleging claims similar to those set forth in the Rosson complaint. The City of Dearborn Police and Retirement System and Martin Rosson agreed, with the consent of the Company and Brookfield, to consolidate their respective claims and such consolidation was approved by the Court during the first quarter of 2020. While the Company believes that these claims are without merit, it cannot predict with certainty the ultimate resolution of any proceedings brought in connection with these claims.

Chile Project Arbitration

              On September 5, 2016, Compañía Minera del Pacífico (“CMP”) submitted demands for arbitration against the subsidiary of the Company that owns its solar project located in Chile and against the latter’s immediate holding company to the Santiago Chamber of Commerce’s Center for Arbitration and Mediation (“CAM”). The demands alleged, among other things, that the Chile project was not built, operated and maintained according to the relevant standards using prudent utility practices as required by the electricity supply agreement (the “Contract for Difference”) between the parties, entitling them to terminate the Contract for Difference. CMP further alleged that it is entitled to damages based on alleged breaches of a call option agreement entered into by the parties.

In June 2019, the CAM issued two rulings in which it unanimously rejected the claims made by CMP. CMP indicated

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that they would not seek to appeal the ruling and the window in which they are permitted to appeal the ruling has now closed.

Other matters

Two of the Company’s project level subsidiaries are parties to litigation that is seeking to recover alleged underpayments of tax grants under Section 1603 of the American Recovery and Reinvestment Tax Act from the U.S. Department of Treasury (“U.S. Treasury”). These project level subsidiaries filed complaints at the Court of Federal Claims on March 28, 2014. The U.S. Treasury counterclaimed and both claims went to trial in July 2018. In January 2019, the Court of Federal Claims entered judgments against each of the project level subsidiaries for approximately $10.0 million in the aggregate. These judgments are being appealed. The project level subsidiaries expect that losses, if any, arising from these claims would be covered pursuant to an indemnity and, accordingly, the Company recognized a corresponding indemnification asset within other current assets in the consolidated balance sheets as of December 31, 2019 and December 31, 2018.

Issuance of Shares upon Final Resolution of Certain Litigation Matters

Pursuant to the definitive merger and sponsorship agreement (the “Merger Agreement”) entered into with Orion Holdings on March 6, 2017, the Company has agreed to issue additional shares of Common Stock to Orion Holdings for no additional consideration in respect of the Company’s net losses, such as out-of-pocket losses, damages, costs, fees and expenses, in connection with the obtainment of a final resolution of certain specified litigation matters (including the litigation brought by the First Wind Sellers, Mr. Perez and Mr. Domenech described above) within a prescribed period following the final resolution of such matters. The number of additional shares of Common Stock to be issued to Orion Holdings is subject to a pre-determined formula as set forth in the Merger Agreement and is described in greater detail in the Company’s Definitive Proxy Statement on Schedule 14A filed with the SEC on September 6, 2017. The issuance of additional shares to Orion Holdings would dilute the holdings of the Company’s common stockholders and may negatively affect the value of the Company’s Common Stock.

The settlement with Mr. Perez was paid entirely from insurance proceeds and no shares have been issued to Brookfield in connection with the settlement. As of the date hereof, the Company is unable to predict the quantum of any net losses arising from any of the litigation brought by the First Wind Sellers or Mr. Domenech described above or the number of additional shares, if any, that may be required to be issued to Orion Holdings pursuant to the terms of the Merger Agreement in connection with any final resolution of such matters.

21. RELATED PARTIES

As discussed in Note 1. Nature of Operations and Organization, the Company is a controlled affiliate of Brookfield. Brookfield held approximately 62% of the voting securities of TerraForm Power’s Common Stock as of December 31, 2019. Certain affiliates of Brookfield hold the outstanding IDRs of Terra LLC held by certain affiliates of Brookfield, and the Company and the Brookfield IDR Holder entered into an amended and restated limited liability company agreement of Terra LLC as discussed below under Brookfield Sponsorship Transaction, which adjusted the distribution thresholds and percentages applicable to the IDRs.

Brookfield Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal from Brookfield Renewable Partners L.P., an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a Special Committee of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into the Reorganization Agreement for Brookfield Renewable to acquire all of the Company's outstanding shares of Common Stock, other than the approximately 62% currently owned by Brookfield Renewable and its affiliates. Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately

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prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

Brookfield Sponsorship Transaction

As discussed in Note 1. Nature of Operations and Organization, the Company entered into a suite of agreements with Brookfield and/or certain of its affiliates providing for sponsorship arrangements, as are more fully described below.

Brookfield Master Services Agreement

The Company entered into a master services agreement (the “Brookfield MSA”) with Brookfield and certain affiliates of Brookfield (collectively, the “MSA Providers”) pursuant to which the MSA Providers provide certain management and administrative services to the Company, including the provision of strategic and investment management services. As consideration for the services provided or arranged for by Brookfield and certain of its affiliates pursuant to the Brookfield MSA, the Company pays a base management fee on a quarterly basis that is paid in arrears and calculated as follows:

•for each of the first four quarters following the closing date of the Merger, a fixed component of $2.5 million per quarter (subject to proration for the quarter including the closing date of the Merger) plus 0.3125% of the market capitalization value increase for such quarter;

•for each of the next four quarters, a fixed component of $3.0 million per quarter adjusted annually for inflation plus 0.3125% of the market capitalization value increase for such quarter; and

•thereafter, a fixed component of $3.75 million per quarter adjusted annually for inflation plus 0.3125% of the market capitalization value increase for such quarter.

For purposes of calculating the quarterly payment of the base management fee, the term market capitalization value increase means, for any quarter, the increase in value of the Company’s market capitalization for such quarter, calculated by multiplying the number of outstanding shares of common stock as of the last trading day of such quarter by the difference between (x) the volume-weighted average trading price of a share of common stock for the trading days in such quarter and (y) $9.52. If the difference between (x) and (y) in the market capitalization value increase calculation for a quarter is a negative number, then the market capitalization value increase is deemed to be zero.

Pursuant to the Brookfield MSA, the Company recorded charges of $26.8 million and $14.6 million within General and administrative expenses - affiliate in the consolidated statements of operations for the year ended December 31, 2019 and 2018, respectively. The balance payable under the Brookfield MSA was $8.6 million and $4.2 million in the consolidated balance sheets as of December 31, 2019 and 2018, respectively.

Relationship Agreement

The Company entered into a relationship agreement (the “Relationship Agreement”) with Brookfield, which governs certain aspects of the relationship between Brookfield and the Company. Pursuant to the Relationship Agreement, Brookfield agrees that the Company will serve as the primary vehicle through which Brookfield and certain of its affiliates will own operating wind and solar assets in North America and Western Europe and that Brookfield will provide the Company, subject to certain terms and conditions, with a right of first offer on certain operating wind and solar assets that are located in such countries and developed by persons sponsored by or under the control of Brookfield. The rights of the Company under the Relationship Agreement are subject to certain exceptions and consent rights set out therein. See Item 1A. Risk Factors. Risks Related to our Relationship with Brookfield. The Company did not acquire any renewable energy facilities from Brookfield during the years ended December 31, 2019 and 2018.

Terra LLC Agreement

BRE Delaware, Inc. (the “Brookfield IDR Holder”), an indirect, wholly-owned subsidiary of Brookfield, holds all of the outstanding IDRs of Terra LLC. The Company, Brookfield IDR Holder and TerraForm Power Holdings, Inc. are party to the limited liability company agreement of Terra LLC (as amended from time to time, the “Terra LLC Agreement”). Under the Terra LLC Agreement, IDRs are payable when distributions on Common Stock reach a certain threshold. The IDR threshold for

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a first distribution is $0.93 per share of Common Stock and for a second distribution is $1.05 per share of Common Stock. There were no IDR payments made by the Company pursuant to the Terra LLC Agreement during the years ended December 31, 2019 and 2018.

Registration Rights Agreement

The Company entered into a registration rights agreement (the “Registration Rights Agreement”) on October 16, 2017 with Orion Holdings. On June 11, 2018, Orion Holdings, Brookfield BRP Holdings (Canada) Inc. and the Company entered into a Joinder Agreement pursuant to which Brookfield BRP Holdings (Canada) Inc. became a party to the Registration Rights Agreement. On June 29, 2018, a second Joinder Agreement was entered into among Orion Holdings, Brookfield BRP Holdings (Canada) Inc., BBHC Orion Holdco L.P. and the Company pursuant to which BBHC Orion Holdco L.P. became a party to the Registration Rights Agreement. The Registration Rights Agreement governs the rights and obligations of the parties thereto with respect to the registration for resale of all or a part of the Class A shares held by Orion Holdings, BBHC Orion Holdco L.P and such other affiliates of Brookfield from time to time to the Registrations Rights Agreement.

Sponsor Line Agreement

On October 16, 2017, the Company entered into the Sponsor Line with Brookfield and one of its affiliates (the “Lenders”). The Sponsor Line establishes a $500.0 million secured revolving credit facility and provides for the Lenders to commit making LIBOR loans to the Company during a period not to exceed three years from the effective date of the Sponsor Line (subject to acceleration for certain specified events). The Company may only use the revolving Sponsor Line to fund all or a portion of certain funded acquisitions or growth capital expenditures. The Sponsor Line terminates, and all obligations thereunder become payable, no later than October 16, 2022. Borrowings under the Sponsor Line bear interest at a rate per annum equal to a LIBOR rate determined by reference to the costs of funds for U.S. dollar deposits for the interest period relevant to such borrowing adjusted for certain additional costs, in each case plus 3.00% per annum. In addition to paying interest on outstanding principal under the Sponsor Line, the Company is required to pay a standby fee of 0.50% per annum in respect of the unutilized commitments thereunder, payable quarterly in arrears. As a consideration for entering into the Sponsor Line credit facility, the Company paid Brookfield an upfront fee of $5.0 million representing 1.00% of the credit facility amount during the year ended December 31, 2017, which is recorded, less the cumulative amortization expense, within other assets in the consolidated balance sheets. The Company is permitted to voluntarily reduce the unutilized portion of the commitment amount and repay outstanding loans under the Sponsor Line at any time without premium or penalty, other than customary “breakage” costs. TerraForm Power’s obligations under the Sponsor Line are secured by first-priority security interests in substantially all assets of TerraForm Power, including 100% of the capital stock of Terra LLC, in each case subject to certain exclusions set forth in the credit documentation governing the Sponsor Line. Under certain circumstances, the Company may be required to prepay amounts outstanding under the Sponsor Line. During the year ended December 31, 2018, the Company made two draws on the Sponsor Line totaling $86.0 million that were used to fund part of the purchase price of the acquisition of Saeta and repaid such amounts in full. As of December 31, 2019, and December 31, 2018, respectively, there were no amounts drawn under the Sponsor Line. Total interest expense, including the amortization of the deferred financing costs incurred on the Sponsor Line for the years ended December 31, 2019, 2018, and 2017, amounted to $4.2 million, $5.2 million, and $0.9 million, respectively.

Governance Agreement

In connection with the consummation of the Merger, the Company entered into a governance agreement (the “Governance Agreement”) with Orion Holdings and any controlled affiliate of Brookfield (other than the Company and its controlled affiliates) that by the terms of the Governance Agreement from time to time becomes a party thereto. The Governance Agreement establishes certain rights and obligations of the Company and controlled affiliates of Brookfield that own voting securities of the Company relating to the governance of the Company and the relationship between such affiliates of Brookfield and the Company and its controlled affiliates. On June 11, 2018, Orion Holdings, Brookfield BRP Holdings (Canada) Inc. and the Company entered into a Joinder Agreement pursuant to which Brookfield BRP Holdings (Canada) Inc. became a party to the Governance Agreement. On June 29, 2018, a second Joinder Agreement was entered into among Orion Holdings, Brookfield BRP Holdings (Canada) Inc., BBHC Orion Holdco L.P. and the Company pursuant to which BBHC Orion Holdco L.P. became a party to the Governance Agreement.

New York Office Lease & Co-tenancy Agreement

In May 2018 and in connection with the relocation of the Company’s corporate headquarters to New York City, the Company entered into a lease for office space and related co-tenancy agreement with affiliates of Brookfield for a ten-year

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term. The Company recorded $0.9 million and $0.8 million of charges within general and administrative expenses - affiliate in the consolidated statements of operations during the years ended December 31, 2019 and 2018, respectively.

Amended and Restated Terra LLC Agreement

As discussed above, SunEdison transferred all of the outstanding IDRs of Terra LLC held by SunEdison or certain of its affiliates to Brookfield IDR Holder at the effective time of the Merger, and the Company and Brookfield IDR Holder entered into an amended and restated limited liability company agreement of Terra LLC (as amended from time to time, the “New Terra LLC Agreement”). The New Terra LLC Agreement, among other things, reset the IDR thresholds of Terra LLC to establish a first distribution threshold of $0.93 per share of Common Stock and a second distribution threshold of $1.05 per share of Common Stock. As a result of the New Terra LLC Agreement, amounts distributed from Terra LLC are distributed on a quarterly basis as follows:

•first, to the Company in an amount equal to the Company’s outlays and expenses for such quarter;

•second, to holders of Class A units, until an amount has been distributed to such holders of Class A units that would result, after taking account of all taxes payable by the Company in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Common Stock of $0.93 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Common Stock) if such amount were distributed to all holders of shares of Common Stock;

•third, 15% to the holders of the IDRs and 85% to the holders of Class A units until a further amount has been distributed to holders of Class A units in such quarter that would result, after taking account of all taxes payable by the Company in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Common Stock of an additional $0.12 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Common Stock) if such amount were distributed to all holders of shares of Common Stock; and

•thereafter, 75% to holders of Class A units and 25% to holders of the IDRs.

The Company made no IDR payments during the years ended December 31, 2019 and 2018.

Other Brookfield Transactions and Agreements

2018 Private Placement

As discussed in Note 16. Stockholders' Equity, on June 11, 2018, pursuant to a support agreement between Brookfield and the Company, the Company completed the 2018 Private Placement, whereby affiliates of Brookfield purchased 60,975,609 shares of Common Stock at a price per share of $10.66, representing total consideration of approximately $650.0 million. Immediately upon completion of the 2018 Private Placement, affiliates of Brookfield held approximately 65% of TerraForm Power’s Common Stock as of the date thereof.

2019 Private Placement

As discussed in Note 16. Stockholders’ Equity, concurrent with the Company’s Public Offering on October 8, 2019, the Company completed the 2019 Private Placement, whereby affiliates of Brookfield purchased 2,981,514 shares of Common Stock at a price per share of $16.77, representing total consideration of $50.0 million. Upon completion of the Public Offering and the 2019 Private Placement, as of December 31, 2019, affiliates of Brookfield held approximately 62% of TerraForm Power’s Common Stock.

1Acquisition-related Services

During the year ended December 31, 2019, an affiliate of Brookfield incurred $1.4 million for services and fees payable on behalf of the Company in relation to acquisitions in Spain. These costs primarily represent professional fees for legal, valuation and accounting services.

In connection with bank guarantees issued in support of the Saeta acquisition (Note 3. Acquisitions and Divestitures), Brookfield provided credit support to the Company, and the Company agreed to pay a fee to Brookfield equal to 50% of the savings realized by the Company as a result of Brookfield’s provision of credit support, which amounted to $2.9 million and was paid in the second quarter of 2018. The bank guarantees were canceled following the acquisition of Saeta and no amounts remain outstanding thereunder.

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During the year ended December 31, 2018, the Company paid an affiliate of Brookfield $4.0 million for services and fees paid on behalf of the Company by affiliates of Brookfield in relation to the acquisition of Saeta. These costs primarily represent investment banker advisory fees and professional fees for legal and accounting services.

Recovery of Short-swing Profit Claim

During the year ended December 31, 2018, the Company received $3.7 million from Brookfield and certain of its affiliates for the settlement of claims relating to certain transactions under Section 16 (b) of the Exchange Act. The Company recognized the net proceeds of $3.0 million as a capital contribution from a stockholder and recorded it as an increase to additional paid-in capital, which is reflected within the other line in the consolidated statements of stockholders’ equity for the year ended December 31, 2018.

Commodity Contracts

During the year December 31, 2018, the Company entered into agreements with an affiliate of Brookfield regarding the financial swap of certain commodity contracts. These agreements were entered on a flow-through, cost-reimbursement basis, and did not result in any fees or other amounts payable by the Company to any Brookfield affiliate. During the years ended December 31, 2019 and 2018, a total of $0.5 million and $1.2 million, respectively, was recorded pursuant to these agreements on a cost-reimbursement basis by the Company to the Brookfield counterparty.

Chamblee Class Action Settlement

As discussed in Note 16. Stockholders’ Equity, on August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Common Stock to Orion Holdings in connection with the net losses incurred as a result of the final resolution of the Chamblee Class Action.

Due from affiliates

The $0.5 million and $0.2 million due from affiliates amount reported on the consolidated balance sheets as of December 31, 2019 and 2018, respectively, represents a receivable from certain affiliates of Brookfield, as a result of payments made by the Company on their behalf, primarily related to professional fees and rent for shared corporate headquarters, compensation for certain employees that provided services to both companies and certain information technology services. There was no right of set-off with respect to these receivables from affiliates and the payables to the other Brookfield affiliates described herein, and thus these amounts were separately reported in due from affiliate in the consolidated balance sheets.

Due to affiliates

The $11.5 million due to affiliates amount reported on the consolidated balance sheets as of December 31, 2019, represented (i) $8.6 million payables to affiliates of Brookfield for the Brookfield MSA base management fee for the fourth quarter of 2019, (ii) $1.4 million for services and fees incurred by an affiliate of Brookfield on behalf of the Company related to acquisitions in Spain, (iii) $0.6 million standby fee payable under the Sponsor Line, (iv) $0.5 million payable for commodity contracts executed on behalf of the Company on a cost-reimbursement basis, and (v) $0.4 million payables related to rent, office charges and other services to affiliates of Brookfield related to the Company’ corporate headquarters in New York.

The $7.0 million due to affiliates amount reported in the consolidated balance sheets as of December 31, 2018, primarily represented payables to affiliates of Brookfield of $4.2 million for the Brookfield MSA quarterly base management fee for the fourth quarter of 2018 and $2.8 million for leasehold improvements, rent, office charges and other services associated with the transition to the Company’s new corporate headquarters during 2018.

During the year ended December 31, 2019, the Company paid affiliates of Brookfield $22.4 million for the Brookfield MSA base management fee, $1.9 million representing standby fee interest payable under the Sponsor Line, and $3.6 million for leasehold improvements, rent, office charges and other services with affiliates of Brookfield. During the year ended December 31, 2018, the Company paid $14.0 million for the Brookfield MSA base management, $4.0 million for services and fees paid on behalf of the Company by affiliates of Brookfield related to the acquisition of Saeta; and $3.6 million of additional Sponsor Line standby fee interest. Furthermore, in connection with a bank guarantee issued in support of the Saeta acquisition, Brookfield provided credit support to the Company, and the Company agreed to pay a fee to Brookfield an amount equal to

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50% of the savings realized by the Company as a result of Brookfield’s provision of credit support, which amounted to $2.9 million and was paid in the second quarter of 2018.

Agreements with X-Elio Energy

As discussed in Note 3. Acquisitions and Divestitures, on December 18, 2019, the Company acquired an approximately 45 MW portfolio of utility-scale solar photovoltaic power plants in Spain from subsidiaries of X-Elio Energy, S.L. (“X-Elio”). Contemporaneously with the closing of the X-Elio Acquisition, Brookfield and certain of its institutional partners entered into a 50-50 joint venture in respect of X-Elio.

The X-Elio Acquisition was pursuant to three share purchase agreements with X-Elio (collectively the “X-Elio SPAs”), pursuant to which the Company acquired three X-Elio subsidiaries. In connection with the X-Elio Acquisition, on the closing date, the Company entered into a Transitional Services Agreement (the “X-Elio TSA”) with X-Elio. The X-Elio TSA provides for X-Elio to support the Company on a transitional basis by providing certain accounting and other services for an initial three-month term that may be extended at the election of the Company for an additional three-month term. In addition, the subsidiaries acquired by the Company on the closing date were party to existing O&M agreements with X-Elio (collectively, the “X-Elio O&M Agreements”), pursuant to which X-Elio provided O&M services to the acquired solar power facilities. Under the terms of the X-Elio SPAs, the X-Elio O&M Agreements will remain in effect for a maximum 12-month term after the closing date, subject to earlier termination at the Company’s election, for a total consideration of €1.0 million per annum (equivalent to $1.1 million as of December 31, 2019). Under the X-Elio SPAs, certain indemnity and other obligations remain in place post-closing of the acquisition but no post-closing payments are expected to be made by either party in the ordinary course.

SunEdison Matters

SunEdison Bankruptcy and Settlement Agreement with SunEdison

As discussed in Note 1. Nature of Operations and Organization, TerraForm Power entered into the Settlement Agreement with SunEdison on March 6, 2017, which was approved by the Bankruptcy Court. The settlements, mutual intercompany releases, and certain other terms and conditions became effective upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017. The effectiveness of these Settlement Agreement provisions has resolved claims between TerraForm Power and SunEdison, including, among other things, claims of SunEdison against the Company for alleged fraudulent and preferential transfers and claims of the Company against SunEdison, including those outlined in the initial proof of claim filed by the Company in the SunEdison Bankruptcy on September 25, 2016, and on October 7, 2016. Under the Settlement Agreement, all such claims have been mutually released. Moreover, with certain limited exceptions, any agreements between SunEdison Debtors and SunEdison parties to the Settlement Agreement on the one hand and the Company, on the other hand, have been deemed rejected without further liability, claims, or damages on the part of the Company. These exceptions included directors’ and officers’ liability insurance allocation agreements and certain corporate and project-level transition services agreements.

Historical Management Services Agreement with SunEdison

Historically, general and administrative expenses - affiliate primarily represented costs incurred by SunEdison for services provided to the Company pursuant to the management services agreement (the “SunEdison MSA”). Pursuant to the SunEdison MSA, SunEdison agreed to provide or arrange for other service providers to provide management and administrative services to the Company. As consideration for the services provided, the Company agreed to pay SunEdison a base management fee equal to 2.5% of the Company’s cash available for distribution in 2017 but not to exceed $9.0 million. Subsequent to the SunEdison Bankruptcy, SunEdison continued to provide some of these services, including services related to information technology, human resources, tax, treasury, finance and controllership, but stopped providing or reimbursing the Company for other services.

The Company entered into a corporate-level transition services agreement with SunEdison on September 7, 2017 that covered the services that SunEdison continued to provide under the SunEdison MSA and retroactively applied to transition services provided since February 1, 2017. The Company paid SunEdison certain monthly fees in exchange for these services at rates consistent with past practice. Amounts incurred by the Company under this transition services agreement with SunEdison and by SunEdison under the SunEdison MSA totaled $4.5 million for the year ended December 31, 2017, and are reported within general and administrative expenses - affiliate in the consolidated statements of operations. As discussed above, the SunEdison MSA was rejected without further liability, claims or damages on the part of the Company pursuant to the Settlement Agreement upon the closing of the Merger. The corporate-level transition services agreement was extended through

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the end of the fourth quarter of 2017 with respect to certain information technology services. Amounts incurred for these services subsequent to the Merger closing date on October 16, 2017 are included within general and administrative expenses in the consolidated statements of operations since SunEdison was no longer an affiliate of the Company.

Historical O&M and Asset Management Services with SunEdison

O&M services, as well as asset management services, were historically provided to the Company substantially by SunEdison pursuant to contractual agreements. The Company has completed its transition away from SunEdison for these services, except for services provided to its 101.6 MW renewable energy facility in Chile. In the first half of 2017, the Company entered into certain transition services agreements with SunEdison to facilitate this transition. These transition services agreements allowed the Company, among other things, to hire employees of SunEdison that were performing these project-level services for the Company and to terminate project-level asset management and O&M services on 10 days advance notice. Total costs incurred for O&M and asset management services from SunEdison were $17.6 million and $26.7 million during the years ended December 31, 2017 and 2017, respectively, and are reported as cost of operations - affiliate in the consolidated statements of operations. Amounts incurred for O&M and asset management services from SunEdison subsequent to the Merger closing date on October 16, 2017 are included within cost of operations in the consolidated statements of operations since SunEdison was no longer an affiliate of the Company.

Historical Engineering, Procurement and Construction Contracts and Module Warranties

SunEdison served as the prime construction contractor for most of the Company’s renewable energy facilities acquired from SunEdison pursuant to engineering, procurement and construction contracts with the Company’s project-level subsidiaries. The Company also generally obtained solar module warranties from SunEdison, including workmanship warranties and output guarantees, for those solar facilities that the Company acquired from SunEdison that utilized SunEdison modules. Third party insurance was procured by SunEdison to back-stop payment of warranty claims for SunEdison modules purchased from January of 2011 through January of 2017.

During the first quarter of 2017, the Company received $7.0 million from SunEdison in satisfaction of outstanding claims made under engineering, procurement and construction contracts, of which $4.8 million related to the Company’s renewable energy facility located in Chile and compensated the relevant project company as the facility’s performance during the warranty period was below that guaranteed by an affiliate of SunEdison under the applicable EPC contract. These receipts were treated as equity contributions from SunEdison within Net SunEdison investment on the consolidated statements of stockholders’ equity for the year ended December 31, 2017. As discussed above, pursuant to the Settlement Agreement entered into with SunEdison, and upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017, these construction and related contracts were rejected without further liability, claims or damages on the part of the Company.

Insurance Allocation Agreements

The Company, TerraForm Global, SunEdison and certain of their respective directors and officers shared $150.0 million of directors’ and officers’ liability insurance policies that covered the period from July 15, 2015 to July 14, 2016 (the “D&O Insurance”). SunEdison and the independent directors of SunEdison entered into an agreement, dated March 27, 2017 and amended on June 7, 2017, with the Company, TerraForm Global, their respective current directors (as of that date) and certain of their respective current officers (as of that date) (the “YieldCo D&O Parties”) related to the D&O Insurance, which included, among other things, an agreement by SunEdison to consent to proposed settlements of up to $32.0 million to be funded from the D&O Insurance for certain lawsuits against the YieldCo D&O Parties. The agreement was approved by the Bankruptcy Court on June 28, 2017.

On August 31, 2017, the Company, TerraForm Global, SunEdison and certain of their respective current and former directors and officers entered into a second agreement related to the D&O insurance, which provided, among other things, that no party to the second D&O insurance allocation agreement would object to the settlement of the Chamblee Class Action (as discussed in Note 20. Commitments and Contingencies) with the use of $13.6 million of the D&O insurance. On September 11, 2017, the Bankruptcy Court granted approval of the second D&O insurance allocation. In connection with the second D&O insurance allocation agreement, the Company and TerraForm Global entered into an agreement pursuant to which TerraForm Global agreed to indemnify and reimburse the Company for certain legal costs and expenses related to the defense or settlement of the Chamblee Class Action that are not covered by the D&O insurance.

In addition to the insurance allocation agreements, from time to time, the Company agreed to orders or stipulations with SunEdison and TerraForm Global in connection with the SunEdison Bankruptcy related to, among other things, insurance proceeds, interim operating protocols, bankruptcy filing protocols and other matters.

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Net SunEdison Investment

During the year ended December 31, 2017, SunEdison made net contributions to Terra LLC pursuant to the related party agreements discussed above and in connection with drop down acquisitions. The following table illustrates the detail of Net SunEdison investment for the year ended December 31, 2017, as reported in the consolidated statements of stockholders’ equity:

(in thousands)	Year ended December 31, 2017
General and administrative expenses - affiliate1	$	6,154
TerraForm Power, Inc. equity awards distributed to SunEdison2	(3,372)
Other3	6,986
Net SunEdison investment	$	9,768

———

(1)Represents costs incurred by SunEdison for services provided to the Company pursuant to the SunEdison MSA in excess of cash paid or payable to SunEdison, as well as stock-based compensation expense related to equity awards in the stock of SunEdison and TerraForm Global that was allocated to the Company (as discussed in Note 17. Stock-Based Compensation).

(2)Represents stock-based compensation cost related to equity awards in the Company’s stock which was allocated to SunEdison and TerraForm Global.

(3)Represents cash received from SunEdison in satisfaction of outstanding claims made under engineering, procurement and construction contracts as discussed above.

22. (LOSS) EARNINGS PER SHARE

Basic (loss) earnings per share is computed by dividing net (loss) income attributable to Class A common stockholders by the number of weighted average ordinary shares outstanding during the period. Diluted (loss) earnings per share is computed by adjusting basic (loss) income per share for the impact of the equivalent weighted average dilutive common shares outstanding during the period unless the impact is anti-dilutive. Common equivalent shares represent the incremental shares issuable for unvested restricted Common Stock.

Unvested RSAs that contain non-forfeitable rights to distributions are treated as participating securities and are included in the (loss) earnings per share computation using the two-class method. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that would otherwise have been available to common stockholders. This method determines loss per share based on distributions declared on common stock and participating securities (i.e., distributed earnings), as well as participation rights of participating securities in any undistributed earnings. Undistributed losses are not allocated to participating securities since they are not contractually obligated to share in the losses of the Company. The numerator for undistributed (loss) earnings per share is also adjusted by the amount of deemed distributions related to the accretion of redeemable non-controlling interest since the redemption value of the non-controlling interest was considered to be at an amount other than fair value (and was considered a right to an economic distribution that differed from other common stockholders) and as accretion adjustments were recognized in additional paid-in capital and not within net (loss) income attributable to Class A common stockholders.

Basic and diluted (loss) earnings per share of the Company’s Common Stock for the years ended December 31, 2019,

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2018 and 2017 was calculated as follows:

	Year Ended December 31,
(In thousands, except per share amounts)	2019		2018		2017
Basic and diluted (loss) earnings per share:
Net (loss) income attributable to Class A common stockholders	$	(148,684)	$	12,380	$	(160,154)
Less: accretion of redeemable non-controlling interest	—		—		(6,729)
Less: cash distributions to Class A shares and participating RSAs	—		—		(285,497)
Undistributed income (loss) attributable to Class A shares	(148,684)		12,380		(452,380)
Weighted average basic and diluted Class A shares outstanding1	213,275		182,239		103,866
Distributed earnings per share	—		—		2.75
Undistributed (loss) earnings per share	(0.70)		0.07		(4.36)
Basic and diluted (loss) earnings per share	$	(0.70)	$	0.07	$	(1.61)

———

(1)The computation of diluted earnings per share of the Company’s Common Stock for the year ended December 31, 2019, excluded the impact of 191,936 potentially dilutive unvested RSUs outstanding at December 31, 2019, because the effect would have been anti-dilutive.

23. SEGMENT REPORTING

The Company has three reportable segments: Solar, Wind, and Regulated Solar and Wind. These segments, which represent the Company’s entire portfolio of renewable energy facilities, have been determined based on the management approach. The management approach designates the internal reporting used by management for making decisions and assessing performance as the source of the reportable segments. Each of the Company’s reportable segments represents an aggregation of operating segments. An operating segment is defined as a component of an enterprise that engages in business activities from which it may earn revenues and incur expenses, and that has discrete financial information that is regularly reviewed by the chief operating decision maker (“CODM”) in deciding how to allocate resources. The Company’s Chief Executive Officer and Chief Financial Officer have been identified as the CODMs. The Company’s operating segments consist of: (i) Distributed Generation, North America Solar Utility, International Solar Utility, which are aggregated into the Solar reportable segment; (ii) Northeast Wind, Central Wind, Texas Wind, Hawaii Wind and International Wind operating segments, which are aggregated into the Wind reportable segment; and (iii) the Spanish Regulated Solar and Spanish Regulated Wind operating segments that are aggregated within the Regulated Solar and Wind reportable segment. The International Wind, comprising the Company’s wind operations in Portugal and Uruguay, and the Spanish Regulated Solar and Wind operating segments were added during the second quarter of 2018 upon the acquisition of Saeta and represent its entire operations. See Note 3. Acquisitions and Divestitures for additional details. The operating segments were aggregated as they have similar economic characteristics and meet the aggregation criteria per ASC 280. The CODMs evaluate the performance of the Company’s operating segments principally based on operating income or loss. Corporate expenses include general and administrative expenses, acquisition costs, interest expense on corporate-level indebtedness, stock-based compensation and depreciation expense. All net operating revenues for the years ended December 31, 2019, 2018, and 2017, were earned by the Company’s reportable segments from external customers in the United States (including Puerto Rico), Canada, Spain, Portugal, the United Kingdom, Uruguay and Chile, as applicable.

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The following table reflects summarized financial information for the Company’s reportable segments for the years ended December 31, 2019, 2018 and 2017:

	Year Ended December 31, 2019
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	—	$	941,240
Depreciation, accretion and amortization expense	118,564		175,842		138,213		1,491		434,110
Other operating costs and expenses	66,334		142,031		90,516		94,819		393,700
Operating income (loss)	131,535		(31,734)		109,939		(96,310)		113,430
Interest expense, net	68,441		58,105		54,727		116,869		298,142
Other non-operating (income) expenses, net	(7,893)		(455)		3,994		14,329		9,975
Income tax expense (benefit)	2,309		193		1,326		8,070		11,898
Net income (loss)	$	68,678	$	(89,577)	$	49,892	$	(235,578)	$	(206,585)
Cash Flows
Capital expenditures	$	2,223	$	15,426	$	599	$	2,936	$	21,184
Balance Sheet
Total assets1	3,509,076		3,716,447		2,731,892		101,221		10,058,636

	Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	298,966	$	280,949	$	186,655	$	—	$	766,570
Depreciation, accretion and amortization expense	109,809		151,472		79,026		1,530		341,837
Impairment of renewable energy facilities	15,240		—		—		—		15,240
Other operating costs and expenses	74,778		123,203		46,289		95,244		339,514
Operating income (loss)	99,139		6,274		61,340		(96,774)		69,979
Interest expense, net	63,571		50,712		15,510		119,418		249,211
Other non-operating income, net	(4,248)		(108)		(2,261)		(6,998)		(13,615)
Income tax (benefit) expense	(20,346)		79		10,558		(2,581)		(12,290)
Net income (loss)	$	60,162	$	(44,409)	$	37,533	$	(206,613)	$	(153,327)
Cash Flows
Capital expenditures	$	4,325	$	12,219	$	—	$	5,901	$	22,445
Balance Sheet
Total assets1	2,762,977		3,733,049		2,748,126		86,202		9,330,354

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	Year Ended December 31, 2017
(In thousands)	Solar		Wind		Corporate		Total
Operating revenues, net	$	337,233	$	273,238	$	—	$	610,471
Depreciation, accretion and amortization expense	108,695		135,785		2,240		246,720
Impairment of renewable energy facilities	1,429		—		—		1,429
Other operating costs and expenses	65,213		105,817		150,569		321,599
Operating income (loss)	161,896		31,636		(152,809)		40,723
Interest expense, net	70,439		77,398		114,166		262,003
Other non-operating (income) expenses, net	(36,399)		3,650		67,413		34,664
Income tax benefit	—		—		(19,641)		(19,641)
Net income (loss)	$	127,856	$	(49,412)	$	(314,747)	$	(236,303)
Cash Flows
Capital expenditures	$	302	$	7,670	$	420	$	8,392
Balance Sheet
Total assets1	2,897,036		3,400,858		89,127		6,387,021

———

(1)As of December 31, 2019, 2018 and 2017, respectively.

Operating Revenues, Net

The following table reflects operating revenues, net earned during the years ended December 31, 2019, 2018 and 2017, by geographic location:

	Year Ended December 31,
(In thousands)	2019		2018		2017
United States	$	457,718	$	473,950	$	519,551
Canada	43,672		41,174		44,636
Spain	338,669		186,655		—
Portugal	38,833		17,269		—
United Kingdom	1,639		1,597		15,002
Uruguay	29,573		17,302		—
Chile	31,136		28,623		31,282
Total operating revenues, net	$	941,240	$	766,570	$	610,471

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Long-lived Assets, Net

Long-lived assets, net consist of renewable energy facilities, intangible assets, and goodwill as of December 31, 2019 and 2018. The following table is a summary of long-lived assets, net by geographic area:

	As of December 31,
(In thousands)	2019		2018
United States (including Puerto Rico)	$	5,722,092	$	5,030,483
Canada	366,862		362,829
Spain	2,574,546		2,503,420
Portugal	229,629		251,053
United Kingdom	17,289		13,183
Uruguay	261,189		264,798
Chile	155,098		161,217
Total long-lived assets, net	9,326,705		8,586,983
Current assets	553,347		501,185
Other non-current assets	178,584		242,186
Total assets	$	10,058,636	$	9,330,354

24. CONCENTRATION OF CREDIT RISK

The Company’s financial assets are typically subject to concentrations of credit risk and primarily consist of cash and cash equivalents, accounts receivable and derivative assets. The following table reflects the balances of the major financial assets that are subject to concentrations of credit risk as of December 31, 2019, and 2018:

	As of December 31,
(In thousands)	2019		2018
Cash and cash equivalents	$	349,500	$	392,809
Accounts receivable, net	167,865		145,161
Derivative assets	73,536		105,355
Total	$	590,901	$	643,325

Cash and Cash Equivalents

The Company is subject to concentrations of credit risk related to the cash and cash equivalents that may exceed the insurable limits in the related jurisdictions. The maximum exposure to loss due to credit risk would generally equal the stated value of cash and cash equivalents in the above table. The Company places its cash and cash equivalents with creditworthy financial institutions and, historically, did not experience any losses with regards to balances in excess of insured limits or as a result of other concentrations of credit risk.

Accounts Receivable, Net

The Company serves hundreds of customers in three continents, and, in the United States, the Company’s customers are spread across various states resulting in the diversification of its customer base. Notwithstanding this diversification, a significant portion of the Company’s offtake counterparties are government-backed entities and public utility companies, which has the potential to impact the Company’s exposure to credit risk.

Major Customers

The following table reflects operating revenues, net for the years ended December 31, 2019, 2018 and 2017, by specific customers exceeding 10% of total net operating revenues:

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		Year Ended December 31,
		2019				2018				2017
(In thousands, except for percentages)	Segment	Amount		Percentage		Amount		Percentage		Amount		Percentage
Comisión Nacional de los Mercados y la Competencia1	Regulated Solar and Wind	$	240,714	25.6	%	$	127,912	16.7	%	N/A		N/A
Tennessee Valley Authority2	Wind	93,920		10.0		90,283		11.8		$	79,773	13.1	%
San Diego Gas & Electric3	Solar	N/A		N/A		N/A		N/A		63,905		10.5

———

(1)The Company earned $338.7 million and $186.7 million from the Spanish Electricity System for the years ended December 31, 2019, and 2018, respectively, of which $240.7 million and $127.9 million were through collections from the Comisión Nacional de los Mercados y la Competencia (“CNMC”). These operating revenues were earned within the Regulated Solar and Wind segment and represented 25.6% and 16.7% of the Company’s net consolidated operating revenues for these years, respectively. The CNMC is the state-owned regulator of the Spanish Electricity System who collects the funds payable, mainly from the tariffs to end user customers, and is responsible for the calculation and the settlement of regulated payments.

(2)The Company earned $93.9 million and $90.3 million operating revenues from the Tennessee Valley Authority (“TVA”) for the years ended December 31, 2019, and 2018, respectively. These operating revenues were earned within the Regulated Solar and Wind segment and represented 10.0% and 11.8% of the Company’s net consolidated operating revenues for these years, respectively. The TVA is a corporation wholly-owned by the U.S. government that sells power mainly to wholesale customers in several states in the Southern part on the U.S.

(3)This customer did not exceed 10% of total operating revenue for the year ended December 31, 2019.

The amounts receivable from the CNMC and TVA as of December 31, 2019, and 2018, were as follows:

	As of December 31,
(In thousands)	2019		2018
CNMC	$	78,474	$	64,739
TVA	12,722		9,715
Total	$	91,196	$	74,454

If the CNMC or the TVA were to cease to honor their obligations to the Company it would have a material adverse effect on the Company’s business, operating results or financial position. The Company’s management believes that the concentration of risk with the CNMC is mitigated by, among other things, the indirect support of the Spanish government for the CNMC’s obligations and, in general, by the regulated rate system in Spain. Similarly, the Company’s management believes that the concentration risk of the credit risk with the TVA is mitigated by, among other things, the indirect support of the U.S. government.

Derivative Assets

The Company is subject to credit risk related to its derivatives to the extent the hedge counterparties may be unable to meet the terms of the contractual arrangements. The maximum exposure to loss due to credit risk if counterparties fail completely to perform according to the terms of the contracts would generally equal the fair value of derivative assets presented in the above table. The Company seeks to mitigate credit risk by transacting with a group of creditworthy financial institutions and through the use of master netting arrangements.

167

25. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly consolidated results of operations for the year ended December 31, 2019 were as follows:

(In thousands, except per share data)	Q1		Q2		Q31		Q42,3
Operating revenues, net	$	225,332	$	255,366	$	253,808	$	206,734
Operating income (loss)	29,104		54,928		40,365		(10,967)
Interest expense, net	86,287		71,041		89,393		51,421
Net loss	(36,057)		(16,827)		(62,313)		(91,388)
Net loss attributable to Class A common stockholders	(8,627)		(3,595)		(54,837)		(81,625)
Weighted average Class A common shares outstanding - basic and diluted	209,142		209,142		209,155		217,608
Net loss per weighted average Class A common share - basic and diluted	$	(0.04)	$	(0.02)	$	(0.26)	$	(0.38)

———

(1)During the third quarter of 2019, the Company recorded corrections related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement resulting in an increase in the previously reported accretion and depreciation expense by $3.3 million and $3.7 million, respectively, as a result of this change.

(2)As discussed in Note 3. Acquisitions and Divestitures, on September 26, 2019, the Company completed the WGL Acquisition representing an approximately 320 MW distributed generation portfolio of renewable energy facilities located in the United States. The below table presents selected financial information for the acquired entities as included in the Company’s results for the year ended December 31, 2019:

(In thousands)	Q1	Q2	Q3	Q4
Operating revenues, net	N/A	N/A	N/A	$	13,773
Operating income	N/A	N/A	N/A	166
Net income	N/A	N/A	N/A	80

(3)The fourth quarter of 2019 includes $31.1 million loss on modification and extinguishment of certain corporate and non-recourse project debt. See to Note 10. Long-term Debt for additional details.

(4)The fourth quarter of 2019 includes $2.3 million gain from the sale of six renewable energy facilities with a combined nameplate capacity of approximately 6 MW.

Quarterly consolidated results of operations for the year ended December 31, 2018, were as follows:

(In thousands, except per share data)	Q11,2		Q23,4		Q33,4		Q43,4,5
Operating revenues, net	$	127,547	$	179,888	$	246,042	$	213,093
Operating (loss) income	(22,049)		27,299		56,666		8,063
Interest expense, net	53,554		50,892		72,416		72,349
Net loss	(76,313)		(27,612)		(19,051)		(30,351)
Net income (loss) attributable to Class A common stockholders	82,796		(21,337)		(33,590)		(15,489)
Weighted average Class A common shares outstanding - basic	148,139		161,568		209,142		209,142
Weighted average Class A common shares outstanding - diluted	148,166		161,568		209,142		209,142
Net earnings (loss) per weighted average Class A common share - basic and diluted	$	0.56	$	(0.13)	$	(0.16)	$	(0.07)

———

(1)During the first quarter of 2018, the Company recognized an impairment charge of $15.2 million on renewable energy facilities due to the bankruptcy of a significant customer significant to a distributed generation project (see Note 6. Renewable Energy Facilities).

(2)During the first quarter of 2018, the Company recorded a reduction of $151.2 million to the non-controlling interests balance and a corresponding allocation of net loss attributable to non-controlling interests due to the change in the tax rate input in the HLBV methodology used by the Company. As a result of the reduction of the federal income tax rate from 35% to 21% as specified in the Tax Act, the Company allocated significantly lower amounts to certain non-controlling interests (i.e., tax equity investors) in order to achieve their contracted after-tax rate of return.

168

(3)As discussed in Note 3. Acquisitions and Divestitures, on June 12, 2018 the Company acquired approximately 95.28% of the outstanding shares of Saeta, a Spanish renewable power company with over 1,000 MW of wind and solar facilities (approximately 250 MW of solar and 778 MW of wind) located primarily in Spain. The Company acquired the remaining approximately 4.72% of the shares of Saeta on July 2, 2018. The below table presents selected financial information of Saeta as included in the Company’s results for the year ended December 31, 2018:

(In thousands)	Q1	Q2		Q3		Q4
Operating revenues, net	N/A	$	24,681	$	107,903	$	88,642
Operating income	N/A	10,055		37,212		21,824
Interest (income) expense, net	N/A	(4,114)		13,241		14,405
Net income	N/A	11,545		21,850		4,819

(4)During the second quarter of 2018, the Company discontinued hedge accounting for a certain long-dated commodity contract as it was no longer considered highly effective in offsetting the cash flows associated with the underlying risk being hedged. The gains (losses) in fair value on this commodity contract were recorded in earnings within operating revenues, net and amounted to $10.8 million, $0.9 million and $(5.3) million for the second, third and fourth quarters of 2018, respectively (see Note 12. Derivatives).

(5)During the fourth quarter of 2018, the Company recorded corrections related to the accretion period related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement resulting in a reduction in the previously reported accretion and depreciation expense by $6.3 million and $4.4 million, respectively, as a result of this change.

26. SUBSEQUENT EVENTS

Brookfield Renewable Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal from Brookfield Renewable Partners L.P., an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a Special Committee of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into the Reorganization Agreement for Brookfield Renewable to acquire all of the Company's outstanding shares of Common Stock, other than the approximately 62% currently owned by Brookfield Renewable and its affiliates. Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

Acquisition of 100 MW Concentrated Solar Power Facilities in Spain

On February 11, 2020, TERP Spanish Holdco, S.L.U., a wholly-owned subsidiary of the Company, completed the acquisition of a portfolio of two concentrated solar power facilities located in Spain with a combined nameplate capacity of approximately 100 MW for a total purchase price of approximately €116.8 million (approximately $127.5 million as of the date of the acquisition). These facilities are regulated under the Spanish framework for renewable power, with approximately 19 years of remaining regulatory life. The Company is in the process of evaluating the acquisition accounting considerations, including the determination of the acquisition of a business or a group of assets and the initial purchase price allocation.

169

First Quarter 2020 Distributions

On March 16, 2020, the Company’s Board of Directors declared a cash distribution with respect to Common Stock of $0.2014 per share. The distribution is payable on March 31, 2020 to stockholders of record as of March 27, 2020.

170

EXHIBIT INDEX

Exhibit Number	Description
1.1	Equity Underwriting Agreement, dated October 3, 2019, between TerraForm Power, Inc., TerraForm Power, LLC and RBC Capital Markets, LLC, as representative of the underwriters named therein (incorporated by reference to Exhibit 1.1 to the Registrant’s Form 8-K filed on October 8, 2019.
2.1	Purchase and Sale Agreement, dated as of November 17, 2014, among SunEdison, Inc., TerraForm Power, LLC, TerraForm Power, Inc., First Wind Holdings, LLC, First Wind Capital, LLC, D. E. Shaw Composite Holdings, L.L.C., the company members party thereto and D. E. Shaw Composite Holdings, L.L.C. and Madison Dearborn Capital Partners IV, L.P., acting jointly, solely in their capacity as the representative of the sellers (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed on February 3, 2015).
2.2	First Amendment to the Purchase and Sale Agreement, dated as of January 28, 2015, among SunEdison, Inc., TerraForm Power, LLC and D. E. Shaw Composite Holdings, L.L.C. and Madison Dearborn Capital Partners IV, L.P., acting jointly, solely in their capacity as the representative of the sellers (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K filed on February 3, 2015).
2.3***	Sale and Purchase Agreement, dated as of January 5, 2017, among TerraForm Power Operating, LLC, SunEdison Yieldco UK Holdco 2, LLC and Vortex Solar UK Limited (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 10-Q filed on August 29, 2017).
2.4***	Merger and Sponsorship Transaction Agreement, dated as of March 6, 2017, by and among TerraForm Power, Inc., Orion US Holdings 1 L.P. and BRE TERP Holdings Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed on March 7, 2017).
3.1	Amended and Restated Certificate of Incorporation of TerraForm Power, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed on October 17, 2017).
3.2	Third Amended and Restated Bylaws of TerraForm Power, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 10-Q filed on November 12, 2019).
4.1	Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-1/A, File No. 333-196345, filed on July 3, 2014).
4.2	Third Amended and Restated TERP LLC Operating Agreement, dated as of December 31, 2018, by and among TerraForm Power, Inc., TerraForm Power Holdings, Inc. and BRE Delaware Inc. (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 10-K filed on March 15, 2019).
4.3	Indenture, dated as of December 12, 2017, among TerraForm Power Operating, LLC, the guarantors party thereto and U.S. Bank National Association U.S., as trustee relating to the 4.25% Senior Notes due 2023 (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed on December 12, 2017).
4.4	Form of 4.25% Senior Notes due 2023 (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on December 12, 2017, which exhibit refers to Exhibit A to the Indenture filed therewith as Exhibit 4.1).
4.5	Indenture, dated as of December 12, 2017, among TerraForm Power Operating, LLC, the guarantors party thereto and U.S. Bank National Association U.S., as trustee relating to the 5.00% Senior Notes due 2028 (incorporated by reference to Exhibit 4.3 to the Registrant’s Form 8-K filed on December 12, 2017).
4.6	Form of 5.00% Senior Notes due 2028 (incorporated by reference to Exhibit 4.4 to the Registrant’s Form 8-K filed on December 12, 2017, which exhibit refers to Exhibit A to the Indenture filed therewith as Exhibit 4.3).
4.7	Indenture, dated as of October 16, 2019, among TerraForm Power Operating, LLC, the guarantors party thereto and U.S. Bank National Association U.S., as trustee relating to the 4.75% Senior Notes due 2030 (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed on October 17, 2019.
4.8	Form of 4.75% senior notes due 2030 (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on October 17, 2019, which exhibit refers to Exhibit A to the Indenture filed therewith as Exhibit 4.1).
4.9*	Description of Securities Registered under Section 12 of the Securities Exchange Act of 1934.
10.1	TerraForm Power, Inc. 2018 Third Amended and Restated Long-Term Incentive Plan. (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 10-K filed on March 15, 2019).+
10.2	Master Services Agreement, dated as of October 16, 2017, by and among Brookfield Asset Management Inc., BRP Energy Group L.P., Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P., Brookfield Global Renewable Energy Advisor Limited, TerraForm Power, Inc., TerraForm Power, LLC and TerraForm Power Operating, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on October 17, 2017).

171

10.3	Relationship Agreement, dated as of October 16, 2017, by and among Brookfield Asset Management Inc., TerraForm Power, Inc., TerraForm Power, LLC and TerraForm Power Operating, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on October 17, 2017).
10.4	Governance Agreement, dated as of October 16, 2017, by and among TerraForm Power, Inc., Orion US Holdings 1 L.P. and each member of the Sponsor Group that by the terms of the Governance Agreement becomes a party thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on October 17, 2017).
10.5	Joinder to Governance Agreement, dated as of June 11, 2018, by and between TerraForm Power, Inc., a Delaware corporation, Orion US Holdings 1 L.P., a Delaware limited partnership, and Brookfield BRP Holdings (Canada) Inc., an Ontario corporation (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on June 12, 2018).
10.6	Joinder to Governance Agreement, dated as of June 29, 2018, by and among Orion US Holdings 1 L.P., Brookfield BRP Holdings (Canada) Inc., BBHC Orion Holdco L.P. and TerraForm Power, Inc. (incorporated by reference to Exhibit 99.23 to Amendment No. 17 to Schedule 13D of Brookfield Asset Management Inc. filed on June 29, 2018).
10.7	Brookfield Registration Rights Agreement, dated as of October 16, 2017, by and among Orion US Holdings 1 L.P. and TerraForm Power, Inc. (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on October 17, 2017).
10.8	Joinder to Registration Rights Agreement, dated as of June 11, 2018, by and between TerraForm Power, Inc., a Delaware corporation, Orion US Holdings 1 L.P., a Delaware limited partnership, and Brookfield BRP Holdings (Canada) Inc., an Ontario corporation (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on June 12, 2018).
10.9	Registration Rights Assignment Agreement, dated as of June 29, 2018, by and among TerraForm Power, Inc., Brookfield BRP Holdings (Canada) Inc. and BBHC Orion Holdco L.P. (incorporated by reference to Exhibit 99.22 to Amendment No. 17 to Schedule 13D of Brookfield Asset Management Inc. filed on June 29, 2018).
10.10	SunEdison Registration Rights Agreement, dated as of October 16, 2017, by and among TerraForm Power, Inc., SunEdison, Inc., SunEdison Holdings Corporation and SUNE ML1, LLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K filed on October 17, 2017).
10.11	Credit Agreement, dated as of October 16, 2017, by and among TerraForm Power, Inc., as Borrower, and Brookfield Asset Management Inc., a corporation existing under the laws of the Province of Ontario, and Brookfield Finance Luxembourg S.ÀR.L., a société à responsabilité limitée organized under the laws of the Grand Duchy of Luxembourg, as Lenders (incorporated by reference to Exhibit 10.7 to the Registrant’s Form 8-K filed on October 17, 2017).
10.12	Credit and Guaranty Agreement, dated as of October 17, 2017, among TerraForm Power Operating, LLC, as borrower, TerraForm Power, LLC, as a guarantor, certain subsidiaries of TerraForm Power Operating, LLC, as guarantors, the lenders party thereto from time to time, and HSBC Bank USA, National Association, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on October 17, 2017).
10.13	First Amendment to Credit and Guaranty Agreement, dated as of November 6, 2017, among TerraForm Power Operating, LLC, as borrower, TerraForm Power, LLC, as a guarantor, certain subsidiaries of TerraForm Power Operating, LLC, as guarantors, the lenders party thereto from time to time, and HSBC Bank USA, National Association, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.12 to the Registrant’s Form 10-K filed on March 15, 2019).
10.14	Joinder and Second Amendment to Credit and Guaranty Agreement, dated as of April 27, 2018, among Wells Fargo Bank, National Association, as new lender, TerraForm Power Operating, LLC, as borrower, TerraForm Power, LLC, as a guarantor, certain subsidiaries of TerraForm Power Operating, LLC, as guarantors, the lenders party thereto from time to time, and HSBC Bank USA, National Association, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 10-K filed on March 15, 2019).
10.15	Amendment No. 3 to Credit and Guaranty Agreement, dated as of October 5, 2018, among TerraForm Power Operating, LLC as borrower, TerraForm Power, LLC as a guarantor, certain subsidiaries of TerraForm Power Operating, LLC as guarantors, the lenders party thereto from time to time, and HSBC Bank USA, National Association, as administrative and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on October 9, 2018).
10.16	Amendment No. 4 to Credit and Guaranty Agreement, dated as of October 8, 2019, among TerraForm Power Operating, LLC as borrower, TerraForm Power, LLC as a guarantor, certain subsidiaries of TerraForm Power Operating, LLC as guarantors, the lenders party thereto from time to time, and HSBC Bank USA, National Association, as administrative and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on October 8, 2019).

172

10.17	Irrevocable Undertaking Agreement for the launch and acceptance of the takeover bid for the shares of Saeta Yield, S.A., dated as of February 6, 2018, between TERP Spanish HoldCo, S.L., as the bidder, and Cobra Concesiones, S.L. and GIP II Helios, S.à.r.l, as the selling shareholders (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on February 8, 2018).
10.18	Irrevocable Undertaking Agreement for the launch and acceptance of the takeover bid for the shares of Saeta Yield, S.A., dated as of February 6, 2018, between TERP Spanish HoldCo, S.L., as the bidder, and Mutuactivos, S.A.U., S.G.I.I.C., as the selling shareholder (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on February 8, 2018).
10.19	Irrevocable Undertaking Agreement for the launch and acceptance of the takeover bid for the shares of Saeta Yield, S.A., dated as of February 6, 2018, between TERP Spanish HoldCo, S.L., as the bidder, and Sinergia Advisors 2006, A.V., S.A., as the selling shareholder (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on February 8, 2018).
10.20	Class A Common Stock Purchase Agreement, dated as of June 11, 2018, by and between TerraForm Power, Inc., Orion US Holdings 1 LP and Brookfield BRP Holdings (Canada) Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on June 12, 2018).
10.21	Membership Interest Purchase Agreement, dated July 19, 2019, between TerraForm Arcadia Holdings, LLC, WGL Energy Systems, Inc. and WGSW, Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on July 22, 2019.
10.22	Class A Common Stock Purchase Agreement, dated as of October 8, 2019, by and between TerraForm Power, Inc., Orion US Holdings 1 LP and Brookfield BRP Holdings (Canada) Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on October 8, 2019).
21.1*	List of Subsidiaries of TerraForm Power, Inc. as of December 31, 2019.
23.1*	Consent of Ernst & Young LLP
23.2*	Consent of KPMG LLP
23.3	Report of Independent Registered Public Accounting Firm of TERP Spanish HoldCo, S. L. and Subsidiaries.
31.1*	Certification by the Chief Executive Officer of TerraForm Power, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by the Chief Financial Officer of TerraForm Power, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32*	Certification by the Chief Executive Officer and the Chief Financial Officer of TerraForm Power, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
101.INS	Inline XBRL Instance Document
101.SCH	Inline XBRL Taxonomy Extension Schema Document
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File, formatted in XBRL and contained in Exhibit 101

------

* Filed as an exhibit to this Annual Report.

** This information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended.

*** Annexes, schedules and exhibits have been omitted.

+ Indicates a management contract or compensatory plan or arrangement.

173

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		TERRAFORM POWER, INC.
		(Registrant)
Date:	March 17, 2020	By:	/s/ JOHN STINEBAUGH
			John Stinebaugh
			Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ JOHN STINEBAUGH	Chief Executive Officer	March 17, 2020
John Stinebaugh	(Principal executive officer)
/s/ MICHAEL TEBBUTT	Chief Financial Officer	March 17, 2020
Michael Tebbutt	(Principal financial officer and principal accounting officer)
/s/ BRIAN LAWSON	Director and Chair	March 17, 2020
Brian Lawson
/s/ CAROLYN BURKE	Independent Director	March 17, 2020
Carolyn Burke
/s/ CHRISTIAN S. FONG	Independent Director	March 17, 2020
Christian S. Fong
/s/ HARRY GOLDGUT	Director	March 17, 2020
Harry Goldgut
/s/ RICHARD LEGAULT	Director	March 17, 2020
Richard Legault
/s/ MARK MCFARLAND	Independent Director	March 17, 2020
Mark McFarland
/s/ SACHIN SHAH	Director	March 17, 2020
Sachin Shah

174

EX-4.9

DESCRIPTION OF CAPITAL STOCK

The following is a description of the capital stock of Terraform Power, Inc. (“us,” “our,” “we” or the “Company”). The following description may not contain all of the information that is important to you. To understand it fully, you should read our Amended and Restated Certificate of Incorporation (the “Charter”) and our Third Amended and Restated Bylaws (the “Bylaws”), copies of which have been filed with the SEC as exhibits to our Annual Report on Form 10-K, and the applicable provisions of Delaware law.

Authorized Capitalization

Our authorized capital stock consists of 1,200,000,000 shares of Class A common stock, par value $0.01 per share and 100,000,000 shares of preferred stock, par value $0.01 per share. Delaware law does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of the Nasdaq Global Select Market, where our stock is listed, require stockholder approval in some cases of issuances of stock that equal to or exceed 20% of either (i) the outstanding voting power or (ii) the outstanding number of shares of Class A common stock at the time of the issuance.

Class A Common Stock

Voting Rights

Each share of Class A common stock entitles its holder to one vote with respect to each matter presented to our stockholders on which the holders of Class A common stock are entitled to vote. Holders of our Class A common stock do not have cumulative voting rights. Except in respect of matters relating to the election of directors on our board of directors (the “Board”) and as otherwise provided in our Charter or required by law, all matters to be voted on by holders of our Class A common stock must be approved by a majority of the votes cast by holders of such shares present in person or by proxy at the meeting and entitled to vote on the subject matter. See “—Antitakeover Effects of Delaware Law and our Charter and Bylaws” and “—Stockholder Meetings and Elections and Removals of Directors.”

Dividend Rights

The holders of our outstanding shares of Class A common stock are entitled to receive dividends and distributions (whether payable in cash or otherwise), as may be declared from time to time by the Board out of legally available assets or funds. Dividends upon our Class A common stock may be declared by our Board at any regular or special meeting, and may be paid in cash, in property or in shares of capital stock. Before payment of any dividend, there may be set aside out of any of our funds available for dividends, such sums as the Board deems proper as reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any of our property or for any proper purpose, and the Board may modify or abolish any such reserve. Furthermore, because we are a holding company, our ability to pay dividends on our Class A common stock is limited by restrictions on the ability of our subsidiaries to pay dividends or make other distributions to us, including restrictions under the terms of the agreements governing our indebtedness.

Liquidation Rights

In the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs, holders of our Class A common stock would be entitled to share ratably in our assets that are legally available for distribution to stockholders after payment of our debts and other liabilities and the liquidation preference of any of our outstanding shares of preferred stock.

Other Rights 

Holders of our Class A common stock have no preemptive, conversion or other rights to subscribe for additional shares. All outstanding shares are validly issued, fully paid and non-assessable. The rights, preferences and privileges of the holders of our Class A common stock are subject to, and may be adversely affected by, the rights of the holders of shares of any series of our preferred stock that we may designate and issue in the future. In addition, provisions of our Charter provide some restrictions on the transfer of our Class A common stock.

Listing

Our Class A common stock is listed on the Nasdaq Global Select Market under the symbol “TERP.”

Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock is Computershare Trust Company, N.A. The transfer agent’s address is 33 N. LaSalle St, Suite 1100, Chicago, IL 60602.

Preferred Stock

Our Charter authorizes our Board to provide for the issuance of shares of preferred stock in one or more series and to fix the preferences, powers and relative participating, optional or other special rights, and qualifications, limitations or restrictions thereof, including the dividend rate, conversion rights, voting rights, redemption rights and liquidation preference and to fix the number of shares to be included in any such series without any further vote or action by our stockholders. Any preferred stock so issued may rank senior to our Class A common stock with respect to the payment of dividends or amounts upon liquidation, dissolution or winding up, or both. The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control of our company without further action by the stockholders and may adversely affect the voting and other rights of the holders of Class A common stock. The issuance of preferred stock with voting and conversion rights may adversely affect the voting power of the holders of Class A common stock, including the loss of voting control to others. At present, we have no plans to issue any preferred stock.

Antitakeover Effects of Delaware Law and our Charter and Bylaws

Some provisions of Delaware law, our Charter and our Bylaws contain a number of provisions which may have the effect of encouraging persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our Board rather than pursue non-negotiated takeover attempts, which we believe may result in an improvement of the terms of any such acquisition in favor of our stockholders. However, these provisions will also give our Board the power to discourage acquisitions that some stockholders may favor.

Undesignated Preferred Stock

The ability to authorize undesignated preferred stock will make it possible for our Board to issue preferred stock with rights that are only specified at the time of issuance and could also include superior voting, special approval, dividend or other rights or preferences that benefit only the holders of the preferred stock. These rights could impede the success of any attempt to acquire us. These and other provisions may have the effect of deferring, delaying or discouraging hostile takeovers, or changes in control or management of our company.

Stockholder Meetings and Elections and Removals of Directors

Special Meetings of Stockholders. Our Charter provides that a special meeting of stockholders may be called by (i) the chairperson of the Board, (ii) the Lead Independent Director (as defined in our Bylaws), if any, (iii) the

5

Board, pursuant to a duly adopted resolution or (iv) the secretary of the Company upon the written request, stating the purpose of such meeting, of the holders of a majority of the shares of Class A common stock then outstanding.

Elimination of Stockholder Action by Written Consent. Pursuant to Section 228 of the Delaware General Corporation Law (the “DGCL”), any action required to be taken at any annual or special meeting of our stockholders may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares of our stock entitled to vote thereon were present and voted, unless our Charter provides otherwise. Our Charter specifically provides that any action required or permitted to be taken by our stockholders may be effected only at a duly called annual or special meeting, and that the power of stockholders to consent in writing without a meeting is denied.

Board Vacancies. Any vacancy occurring on our Board and any newly created directorship may be filled only by a majority of the directors remaining in office (even if less than a quorum), subject to the rights of holders of any series of preferred stock and the director designation rights of Brookfield Asset Management Inc. (our “Sponsor”).

Election of Directors. Our Charter provides that, except as provided in any duly authorized certificate of designation for any series of preferred stock, in an uncontested election, each director will be elected by the affirmative vote of the majority of the votes cast with respect to such director at any election meeting at which a quorum is present. However, in the case of an election meeting at which a quorum is present for which the number of director nominees exceeds the number of directors to be elected at such election, each director will be elected by a plurality of the votes cast (instead of by votes cast for or against a nominee). Each director will hold office until the next annual meeting of stockholders and until his or her respective successor is duly elected and qualified, or until the director’s earlier death, resignation or removal. With respect to the stockholder election of the non-sponsor independent directors, for so long as the Master Services Agreement (as defined in our Charter) remains in effect, members of the sponsor group are required to vote (or abstain from voting) the shares of Class A common stock they beneficially own in the same proportion as all other shares of Class A common stock that are voted (or abstained from voting) by stockholders other than members of the sponsor group. Directors may serve consecutive terms.

Removal of Directors. Our Charter provides that, subject to the rights, if any, of the holders of any series of preferred stock to elect and remove directors (with or without cause) and fill the vacancies thereby created (as specified in any duly authorized certificate of designation of any series of preferred stock), one or more or all directors may be removed from office with or without cause by the vote of the holders of shares of Class A common stock representing a majority of the issued and outstanding shares of Class A common stock at an annual meeting of stockholders or at a special meeting of stockholders called for such purpose. With respect to the stockholder removal of the non-sponsor independent directors, for so long as the master services agreement remains in effect, our Sponsor and its controlled affiliates (other than us and our controlled affiliates) are required to vote (or abstain from voting) the shares of Class A common stock they beneficially own in the same proportion as all other shares of Class A common stock that are voted (or abstained from voting) by stockholders other than our Sponsor and its controlled affiliates.

Amendments

Amendments of Certificate of Incorporation. Pursuant to Section 242(b) of the DGCL, to amend our Charter, subject to certain exceptions, the Board must adopt a resolution setting forth the proposed amendment, declaring its advisability and either calling a special meeting of the stockholders or directing that the amendment proposed be considered at the next annual meeting of the stockholders. At the meeting, the affirmative vote of a majority of the outstanding stock entitled to vote thereon is required to adopt such amendment. In addition, if the amendment adversely affects any class of shares, then the affirmative vote of a majority of the outstanding stock of each such class is also required to adopt the amendment.

5

Our Charter further provides that amendments of certain sections of the Charter require an affirmative vote of two-thirds of the combined voting power of all of the then outstanding shares of capital stock eligible to be cast in the election of directors generally voting as a single class, including provisions relating to:

•voting, dividend and liquidation rights of Class A common stock;

•removal of directors;

•indemnification of officers and directors and limitation of the personal liability of directors; and

•amendments to the Charter.

Our Charter further provides that approval of the conflicts committee is required to alter, amend or repeal provisions relating to:

•the powers and composition of the Board;

•amendments to the Bylaws and Board designation of committees;

•filling vacancies in the Board;

•competition and corporate opportunities; and

•amendments to the Charter.

Bylaw Amendments. Our Board will have the power to make, amend, alter, change, add to or repeal our Bylaws or adopt new bylaws by the affirmative vote of a majority of the total number of directors then in office. Any action to make, amend, alter, change, add to or repeal any provision in the Bylaws (i) requiring the approval of the conflicts committee, (ii) setting forth the standards for “independence” that will be applicable to independent directors on the Board and the process for nomination to the Board, and election by our shareholders, of independent directors and (iii) setting out the manner in which the governance agreement is amended shall, in each case, also require the approval of the conflicts committee and, for so long as the governance agreement is in effect, our Sponsor. In addition, any action to make, amend, alter, change, add to or repeal any provision in the Bylaws relating to the designation, appointment, removal, replacement, powers or duties of our officers shall, for so long as the governance agreement is in effect, require the approval of our Sponsor.

Notice Provisions Relating to Stockholder Proposals and Nominees

Our Bylaws also impose some procedural requirements on stockholders who wish to make nominations in the election of directors or propose any other business to be brought before an annual or special meeting of stockholders.

Specifically, a stockholder may (i) bring a proposal before an annual meeting of stockholders, (ii) nominate a candidate for election to our Board at an annual meeting of stockholders, or (iii) nominate a candidate for election to our Board at a special meeting of stockholders that has been called for the purpose of electing directors, only if such stockholder delivers timely notice to our corporate secretary. The notice must be in writing and must include certain information and comply with the delivery requirements as set forth in the Bylaws.

With respect to special meetings of stockholders, our Bylaws provide that only such business shall be conducted as shall have been stated in the notice of the meeting.

Delaware Antitakeover Law

We have opted out of Section 203 of the DGCL. Section 203 provides that, subject to certain exceptions specified in the law, a Delaware corporation shall not engage in certain “business combinations” with any “interested stockholder” for a three-year period following the time that the stockholder became an interested stockholder unless:

5

•prior to such time, our board of directors approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

•upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock outstanding at the time the transaction commenced, excluding certain shares; or

•at or subsequent to that time, the business combination is approved by our board of directors and by the affirmative vote of holders of at least 662⁄3% of the outstanding voting stock that is not owned by the interested stockholder.

Generally, a “business combination” includes a merger, asset or stock sale or other transaction resulting in a financial benefit to the interested stockholder. Subject to certain exceptions, an “interested stockholder” is a person who, together with that person’s affiliates and associates, owns, or within the previous three years did own, 15% or more of our voting stock.

Under certain circumstances, Section 203 makes it more difficult for a person who would be an “interested stockholder” to effect various business combinations with a corporation for a three-year period. The provisions of Section 203 may encourage companies interested in acquiring us to negotiate in advance with our board of directors because the stockholder approval requirement would be avoided if our board of directors approves either the business combination or the transaction that results in the stockholder becoming an interested stockholder. These provisions also may make it more difficult to accomplish transactions that stockholders may otherwise deem to be in their best interests.

5

EX-21.1

List of Subsidiaries of TerraForm Power, Inc.

Name of Entity	Jurisdiction of Organization
TerraForm Power Holdings, Inc.	Delaware
TerraForm Power, LLC	Delaware
TerraForm Power Operating, LLC	Delaware
TerraForm Arcadia Holdings, LLC	Delaware
Arcadia Fuel Cell, LLC	Delaware
SF Echo, LLC	Delaware
ASD Solar Holdings GP, LLC	Delaware
TerraForm Arcadia ASD Holdings, LLC	Delaware
ASD Solar LP	Delaware
TerraForm Arcadia TE Holdings, LLC	Delaware
SFRC, LLC	Delaware
Red Wing MN, LLC	Delaware
IMS MN LLC	Delaware
Eichtens MN, LLC	Delaware
Lind MN, LLC	Delaware
Walz MN LLC	Delaware
TerraForm Arcadia TE Holdings 2, LLC	Delaware
SFGF, LLC	Delaware
WGL Georgia Project Group, LLC	Delaware
TerraForm Arcadia TE Holdings 3, LLC	Delaware
SFEE, LLC	Delaware
Empower Energies AIS Project LLC	Delaware
TerraForm Arcadia TE Holdings 4, LLC	Delaware
SFGF II, LLC	Delaware
TPE Kentuck Solar, LLC	Delaware
Northern Cardinal Solar LLC	North Carolina
WGL Solar LGA9, LLC	Delaware
WGL Solar ABE8, LLC	Delaware
WGL Solar Red Maple, 1 LLC	Delaware
WGL Solar Anderson, LLC	Delaware
WGL Bowie State Project, LLC	Delaware
WGL Susquehanna Project, LLC	Delaware
WGL Solar TEB3, LLC	Delaware
WGL Solar MDT2, LLC	Delaware
WGL Solar Goodhue 1, LLC	Delaware
WGL Solar Cornille, LLC	Delaware
WGL Solar Waterview, LLC	Delaware
WGL Solar Nationals, LLC	Delaware
WGL Solar Seashore, LLC	Delaware

WGL Solar Eichtens II, LLC	Delaware
WGL Solar Guse, LLC	Delaware
WGL Solar Barone, LLC	Delaware
WGL Solar Enter, LLC	Delaware
WGL Solar Lange, LLC	Delaware
WGL Solar Bolduan, LLC	Delaware
WGL Solar Winegar, LLC	Delaware
WGL Solar Athena, LLC	Delaware
WGL Solar DCDGS LLC	Delaware
WGL Solar BDL2, LLC	Delaware
WGL Solar BOS7, LLC	Delaware
WGL Solar Huneke II, LLC	Delaware
Gilcrest Solar Garden LLC	Colorado
Torreys Solar LLC	Colorado
Hudson Solar Garden LLC	Colorado
Crestone Solar LLC	Colorado
Quincy Solar Garden LLC	Colorado
Snowmass Solar LLC	Colorado
Imboden IV Solar LLC	Colorado
Blanca Solar LLC	Colorado
Imboden V LLC	Colorado
Little Bear Solar LLC	Colorado
Arcadia Solar, LLC	Delaware
Sunconnect NY1, LLC	Pennsylvania
GES Megafour, LLC	New York
CGY Sutter’s Landing, LLC	Colorado
CGY Atwater I LLC	Colorado
Little Rock-Pham Solar, LLC	Delaware
CGY New York 1 LLC	New York
SEC Newco, LLC	Delaware
Sunconnect CT3, LLC	Pennsylvania
Soleasing FiT LLC	Nevada
Indy Airport Solar Project II, LLC	Indiana
Morgan Lancaster I LLC	Delaware
Bulldog Energy Airport LLC	Indiana
GES MegaOne, LLC	California
11115 Laurel Canyon FiT, LLC	California
Oak Leaf Solar VIII LLC	Colorado
SunEdison Canada Yieldco Master Holdco, LLC	Delaware
SunEdison Canada Yieldco, LLC	Delaware
SunEdison Canada YieldCo Lindsay, LLC	Delaware
SunEdison Marsh Hill, LLC	Delaware

TerraForm Ontario Solar, LLC	Delaware
TerraForm Canada UTL Solar Holdings, Inc.	British Columbia
TerraForm Canada UTL Intermediate GP Inc.	British Columbia
TerraForm Canada UTL Solar Intermediate Holdings LP	Ontario
TerraForm Canada UTL GP Inc.	British Columbia
TerraForm Canada UTL Solar Holdings LP	Ontario
Lindsay Solar GP Inc.	British Columbia
Lindsay Solar LP	Ontario
Marsh Hill III GP Inc. (f/k/a 2413465 Ontario, Inc.)	British Columbia
Marsh Hill III LP	Ontario
TerraForm Ontario Solar Holdings GP Inc.	British Columbia
TerraForm Ontario Solar LP	Ontario
SunEdison Yieldco Chile Master Holdco, LLC	Delaware
SunEdison Yieldco Chile HoldCo, LLC	Delaware
Amanecer Solar Holding SpA	Republic of Chile
Amanecer Solar Management SpA	Republic of Chile
Amanecer Solar SpA	Republic of Chile
SunEdison Yieldco ACQ1 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ1, LLC	Delaware
SunEdison Yieldco DG-VIII Master Holdco, LLC	Delaware
SunEdison Yieldco DG-VIII Holdings, LLC	Delaware
SunEdison PR DG, LLC	Delaware
SunE Solar VIII, LLC	Delaware
SunE WF CRS, LLC	Delaware
SunE Irvine Holdings, LLC	Delaware
SunE HB Holdings, LLC	Delaware
SunEdison Origination2, LLC	Delaware
SunE Solar VIII 2, LLC	Delaware
SunE GIL1, LLC	Delaware
SunE GIL2, LLC	Delaware
SunE GIL3, LLC	Delaware
SunE Gresham WWTP, LLC	Delaware
SunE WF Bellingham, LLC	Delaware
SunE WF Framingham, LLC	Delaware
SunE KHL PSNJ, LLC	Delaware
SunE WF Dedham, LLC	Delaware
SunE DDR PSNJ, LLC	Delaware
SunE W-PR1, LLC	Puerto Rico
SunE WMT PR3, LLC	Puerto Rico
SunE Irvine, LLC	Delaware
SunE HB, LLC	Delaware
SunE OC PSNJ, LLC	Delaware

SunE GIL Holdings, LLC	Delaware
SunE KHL968 Orange, LLC	Delaware
SunE WF10217 West Hartford, LLC	Delaware
SunE KHL1004 Hillsboro, LLC	Delaware
SunEdison Yieldco UK HoldCo 3 Master Holdco, LLC	Delaware
SunEdison Yieldco UK HoldCo 3, LLC	Delaware
TerraForm Power UK Holdings Limited	United Kingdom
Norrington Solar Farm Limited	United Kingdom
TERP Spanish Holdco, S.L.U..	Spain
Saeta Yield S.A.U.	Spain
Al-Andalus Wind Power, S.L.U.	Spain
Eolica del Guadiana, S.L.U.	Spain
La Caldera Energia Burgos, S.L.U.	Spain
Parque Eolico Santa Catalina, S.L.U.	Spain
Parque Eolico Sierra de las Carbas, S.L.U.	Spain
Parque Eolico Tesosanto, S.L.U.	Spain
Parque Eolico Valcaire, S.L.U.	Spain
Sistema Electrico de Conexion Valcaire, S.L.	Spain
Extresol 1, S.L.U.	Spain
Extresol 2, S.L.U.	Spain
Extresol 3, S.L.U.	Spain
Manchasol 2, Central Termosolar Dos, S.L.	Spain
Serrezuela Solar II, S.L.U.	Spain
Evacuacion Valdecaballeros, S.L.	Spain
Pantenergia, S.A.	Portugal
Lestenergia Exploracao de Parques Eolicos S.A.	Portugal
Gadgetadvantages-Unipessoal LDA	Portugal
Sauru Energia S.A. (fka Derisia, S.A.)	Uruguay
Eskonel Company, S.A.	Uruguay
Viensos, S.A.	Uruguay
Fingano, S.A.	Uruguay
Vengano, S.A.	Uruguay
Cuanto de Luz, S.L.U.	Spain
Calasparrra Sol de Murcia, S.L.U.	Spain
Bondco Iberico 733 Holding, S.L.U. (X-Elio EOS, S.L.)	Spain
Bondco 733, S.A.U. (X-Elio Finance, S.A.)	Spain
Huerto Solar La Alcardetena, S.A.U.	Spain
Planta Solar Villardete 1, S.L.U.	Spain
Planta Solar Villardete 2, S.L.U.	Spain
Planta Solar Villardete 3, S.L.U.	Spain
Planta Solar Villardete 4, S.L.U.	Spain
Planta Solar Villardete 5, S.L.U.	Spain

Planta Solar Villardete 6, S.L.U.	Spain
Planta Solar Villardete 7, S.L.U.	Spain
Planta Solar Villardete 8, S.L.U.	Spain
Planta Solar Villardete 9, S.L.U.	Spain
Planta Solar Villardete 10, S.L.U.	Spain
Planta Solar Villardete 11, S.L.U.	Spain
Planta Solar Villardete 12, S.L.U.	Spain
Planta Solar Villardete 13, S.L.U.	Spain
Planta Solar Villardete 14, S.L.U.	Spain
Planta Solar Villardete 15, S.L.U.	Spain
Planta Solar Villardete 16, S.L.U.	Spain
Planta Solar Villardete 17, S.L.U.	Spain
Planta Solar Villardete 18, S.L.U.	Spain
Planta Solar Villardete 19, S.L.U.	Spain
Planta Solar Villardete 20, S.L.U.	Spain
Inversiones Fotovoltaicas Mallorquinas, S.L.U.	Spain
Planta Fotovoltaica El Losar A5, S.L.U.	Spain
Planta Fotovoltaica El Jarran A6, S.L.U.	Spain
Planta Fotovoltaica Cerro Pelo 26, S.L.U.	Spain
Planta Fotovoltaica Morrita 25, S.L.U.	Spain
Planta Fotovoltaica Roma 67, S.L.U.	Spain
Planta Fotovoltaica Los Solares 68, S.L.U.	Spain
Planta Fotovoltaica La Sierra 69, S.L.U.	Spain
Planta Fotovoltaica El Pontarron 70, S.L.U.	Spain
Planta Fotovoltaica La Solana 71, S.L.U.	Spain
Planta Fotovoltaica Alcoriza 72, S.L.U.	Spain
Planta Fotovoltaica Rillo 73, S.L.U.	Spain
Planta Fotovoltaica El Toro 74, S.L.U.	Spain
Planta Fotovoltaica Aderruz 75, S.L.U.	Spain
Planta Fotovoltaica Padul 76, S.L.U.	Spain
Planta Fotovoltaica La Pedrosa 79, S.L.U.	Spain
Planta Fotovoltaica Cavilla 84, S.L.U.	Spain
Planta Fotovoltaica 85, S.L.U.	Spain
Planta Fotovoltaica La Pedriza 86, S.L.U.	Spain
Planta Fotovoltaica De Monsen Miguel 7, S.L.U.	Spain
Planta Fotovoltaica Los Morales 8, S.L.U.	Spain
Planta Fotovoltaica El Cormau 9, S.L.U.	Spain
Planta Fotovoltaica Cerro de la Villa 10, S.L.U.	Spain
Planta Fotovoltaica El Pozuelo 11, S.L.U.	Spain
Planta Fotovoltaica Pena Mongorrero 12, S.L.U.	Spain
Planta Fotovoltaica Los Altos 80, S.L.U.	Spain
Planta Fotovoltaica La Conejera 81, S.L.U.	Spain

Planta Fotovoltaica La Cervera 82, S.L.U.	Spain
Planta Fotovoltaica Pinocha 83, S.L.U.	Spain
Planta Fotovoltaica Piedrablanca 13, S.L.U.	Spain
Planta Fotovoltaica Los Tomasos 14, S.L.U.	Spain
Planta Fotovoltaica El Balcon 15, S.L.U.	Spain
Planta Fotovoltaica Los Molinos 16, S.L.U.	Spain
Planta Fotovoltaica El Erizal 17, S.L.U.	Spain
Planta Fotovoltaica El Morron 18, S.L.U.	Spain
Planta Fotovoltaica Margeli 19 S.L.U.	Spain
Planta Fotovoltaica Corral del Mancho 20, S.L.U.	Spain
Planta Fotovoltaica La Nevera 21, S.L.U.	Spain
Planta Fotovoltaica El Chaparral 22, S.L.U.	Spain
Planta Fotovoltaica Las Cuevas 23, S.L.U.	Spain
Planta Fotovoltaica Altopelo 24, S.L.U.	Spain
SunEdison Yieldco UK HoldCo 4 Master Holdco, LLC	Delaware
SunEdison Yieldco UK HoldCo 4, LLC	Delaware
SunEdison Yieldco UK HoldCo 2 Master Holdco, LLC	Delaware
SunEdison Yieldco UK HoldCo 2, LLC	Delaware
SunEdison Yieldco DG Master Holdco, LLC	Delaware
SunEdison Yieldco DG Holdings, LLC	Delaware
SunE Solar Construction Holdings #2, LLC	Delaware
SunE Solar Construction #2, LLC	Delaware
BWC Origination 2, LLC	Delaware
SunE CREST 1, LLC	Delaware
SunE CREST 2, LLC	Delaware
SunE CREST 5, LLC	Delaware
SunE CREST 6, LLC	Delaware
SunE CREST 7, LLC	Delaware
SunE CRF8, LLC	Delaware
SunE CRF9, LLC	Delaware
SunE CRF10, LLC	Delaware
SunE CRF12, LLC	Delaware
SunE LPT 1, LLC	Delaware
SunE RBPC1, LLC	Delaware
SunE RBPC3, LLC	Delaware
SunE RBPC4, LLC	Delaware
SunE RBPC6, LLC	Delaware
SunE RBPC7, LLC	Delaware
SunE Solar Berlin I, LLC	Delaware
SunEdison Yieldco Origination Holdings LLC	Delaware
Belchertown Solar, LLC	Delaware
BWC Origination 12, LLC	Delaware

SunE Hubbardston Solar, LLC	Delaware
SunE Solar Mattapoisett I, LLC	Delaware
SunEdison DG14 Holdings, LLC	Delaware
SunEdison JJ Gurabo, LLC	Puerto Rico
Tioga Solar La Paz, LLC	Delaware
Treasure Valley Solar, LLC	Delaware
SunEdison Yieldco Nellis Master Holdco, LLC	Delaware
SunEdison Yieldco Nellis HoldCo, LLC	Delaware
NAFB LP Holdings, LLC	Delaware
MMA NAFB Power, LLC	Delaware
Solar Star NAFB, LLC	Delaware
SunEdison Yieldco Regulus Master Holdco, LLC	Delaware
SunEdison Yieldco Regulus Holdings, LLC	Delaware
SunE Regulus Managing Member, LLC	Delaware
SunE Regulus Equity Holdings, LLC	Delaware
SunE Regulus Holdings, LLC	Delaware
Regulus Solar, LLC	Delaware
SunEdison Yieldco ACQ2 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ2, LLC	Delaware
SunEdison Yieldco ACQ3 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ3, LLC	Delaware
SunEdison Yieldco ACQ9 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ9, LLC	Delaware
Atwell Island Holdings, LLC	Delaware
SPS Atwell Island, LLC	Delaware
SunEdison Yieldco ACQ4 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ4, LLC	Delaware
Yieldco SunEY US Holdco, LLC	Delaware
Green Cove Management, LLC	Florida
SunEY Solar Dev Co., LLC	Delaware
SunEY Solar Funding II, LLC	Delaware
SunEY Solar Funding IV, LLC	Delaware
SS San Antonio West, LLC	California
SunEY Solar Gibbstown, LLC	Delaware
SunEY Solar I, LLC	Delaware
SunEY Solar Liberty, LLC	Delaware
SunEY Solar Ocean City One, LLC	Delaware
SunEY Solar St. Joseph’s LLC	Delaware
SunEY Solar Lindenwold BOE, LLC	Delaware
SunEY Solar Ocean City Two, LLC	Delaware
SunEY Solar Power I, LLC	Delaware
SunEY Sequoia I, LLC	Delaware

SunEY Solar Power II, LLC	Delaware
SunEY Solar Frederick BOE, LLC	Delaware
SunEY Solar Hazlet BOE, LLC	Delaware
SunEY Solar Medford BOE, LLC	Delaware
SunEY Solar Medford Lakes, LLC	Delaware
SunEY Solar Talbot County, LLC	Delaware
SunEY Solar Wayne BOE, LLC	Delaware
SunEY Solar Power III, LLC	Delaware
Solar PPA Partnership One, LLC	New York
SunEY Solar Cresskill BOE, LLC	Delaware
SunEY Solar KMBS, LLC	Delaware
Waldo Solar Energy Park of Gainesville, LLC	Delaware
SunEY Solar Silvermine, LLC	Delaware
SunEY Solar Solomon Schechter, LLC	Delaware
SunEY Solar SWBOE, LLC	Delaware
SunEY Solar WPU, LLC	Delaware
SunEdison Yieldco ACQ5 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ5, LLC	Delaware
SunEdison Yieldco Enfinity Master Holdco, LLC	Delaware
SunEdison Yieldco, Enfinity Holdings, LLC	Delaware
Enfinity SPV Holdings 2, LLC	Delaware
Enfinity Holdings WF LLC	Delaware
Enfinity NorCal 1 FAA LLC	California
Enfinity Arizona 2 CampVerde USD LLC	Arizona
Enfinity Arizona 3 Winslow USD LLC	Arizona
Enfinity BNB Napoleon Solar LLC	Delaware
Enfinity CentralVal 5 LUESD LLC	California
SunEdison Yieldco DGS Master Holdco, LLC	Delaware
SunEdison Yieldco, DGS Holdings, LLC	Delaware
SunE DGS Master Tenant, LLC	Delaware
SunE DGS Owner Holdco, LLC	Delaware
SunE Corcoran SP Owner, LLC	Delaware
SunE Solano SP Owner, LLC	Delaware
SunE Wasco SP Owner, LLC	Delaware
SunE Coalinga SH Owner, LLC	Delaware
SunE Pleasant Valley SP Owner, LLC	Delaware
SunEdison Yieldco ACQ7 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ7, LLC	Delaware
MA Operating Holdings, LLC	Delaware
Fall River Commerce Solar Holdings, LLC	Delaware
Fall River Innovation Solar Holdings, LLC	Delaware
South Street Solar Holdings, LLC	Delaware

Uxbridge Solar Holdings, LLC	Delaware
SunEdison Yieldco ACQ8 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ8, LLC	Delaware
SunEdison DG Operating Holdings-2, LLC	Delaware
SunEdison Yieldco ACQ6 Master Holdco, LLC	Delaware
SunEdison Yieldco ACQ6, LLC	Delaware
TerraForm Power Solar X Holdings, LLC	Delaware
SunE Solar X, LLC	Delaware
SunE J10 Holdings, LLC	Delaware
SunE X Trust Successor, LLC	Delaware
TerraForm Power IVS I Master Holdco, LLC	Delaware
TerraForm Power IVS I Holdings, LLC	Delaware
TerraForm Power IVS I Holdings II, LLC	Delaware
IVS I Services, LLC	Delaware
Imperial Valley Solar 1 Holdings II, LLC	Delaware
Imperial Valley Solar 1 Holdings, LLC	Delaware
Imperial Valley Solar 1 Intermediate Holdings, LLC	Delaware
Imperial Valley Solar 1, LLC	Delaware
TerraForm LPT ACQ Master Holdco, LLC	Delaware
TerraForm LPT ACQ Holdings, LLC	Delaware
TerraForm 2014 LPT II ACQ Holdings, LLC	Delaware
TerraForm Solar Master Holdco, LLC	Delaware
TerraForm Solar Holdings, LLC	Delaware
TerraForm Hudson Energy Solar, LLC	Delaware
Hudson USB ITC Managing Member LLC	Delaware
Hudson USB ITC Managing Member 2 LLC	Delaware
Hudson Solar Macy LLC	Delaware
Hudson USB ITC Tenant LLC	Delaware
Hudson USB ITC Owner LLC	Delaware
Hudson USB ITC Tenant 2 LLC	Delaware
Hudson USB ITC Owner 2 LLC	Delaware
Hudson Solar Project 1 LLC	Delaware
Hudson Solar Project 2 LLC	Delaware
Hudson Solar Project 3 LLC	Delaware
SunEdison Yieldco DG Master Holdco, LLC	Delaware
SunEdison YieldCo DG Holdings, LLC	Delaware
SunEdison YieldCo Origination Holdings LLC	Delaware
SunEdison NC Utility, LLC	Delaware
SunEdison NC Utility 2, LLC	Delaware
SunE Dessie Managing Member, LLC	Delaware
SunE Dessie Equity Holdings, LLC	Delaware
Dessie Solar Center, LLC	North Carolina

Bearpond Solar Center, LLC	North Carolina
SunE NC Lessee Managing Member, LLC	Delaware
SunE NC Lessee Holdings, LLC	Delaware
SunE Bearpond Lessee, LLC	Delaware
SunE Shankle Lessee, LLC	Delaware
SunE Graham Lessee, LLC	Delaware
SunE Bearpond Lessor Managing Member, LLC	Delaware
SunE Graham Lessor Managing Member, LLC	Delaware
SunE Shankle Lessor Managing Member, LLC	Delaware
SunE Bearpond Lessor Holdings, LLC	Delaware
SunE Graham Lessor Holdings, LLC	Delaware
Graham Lessor Holdings Corporation	Delaware
SunE Shankle Lessor Holdings, LLC	Delaware
Shankle Lessor Holdings Corporation	Delaware
Shankle Solar Center, LLC	North Carolina
Graham Solar Center, LLC	North Carolina
TerraForm CD ACQ Master Holdco, LLC	Delaware
TerraForm CD ACQ Holdings, LLC	Delaware
TerraForm CD Intermediate Holdings, LLC	Delaware
Capital Dynamics US Solar AIV-A, LLC	Delaware
Capital Dynamics US Solar-PA 1, LLC	Delaware
BASD Buchanan Solar LLC	Delaware
BASD East Hills Solar LLC	Delaware
BASD Farmersville Solar LLC	Delaware
BASD Freedom Solar I LLC	Delaware
BASD Solar LLC	Delaware
BASD Spring Garden Solar LLC	Delaware
CIT Solar LLC	Delaware
Colonial Solar LLC	Delaware
Laureldale Solar LLC	Delaware
Capital Dynamics US Solar AIV-B, LLC	Delaware
CD US Solar Marketing 2, LLC	Delaware
CD US Solar MT 2, LLC	Delaware
CD US Solar PO 2, LLC	Delaware
CD US Solar Sponsor 2, LLC	Delaware
Capital Dynamics US Solar AIV-C, LLC	Delaware
Capital Dynamics US Solar-CA 2, LLC	Delaware
Cami Solar, LLC	Nevada
Capital Dynamics US Solar AIV-D, LLC	Delaware
CD US Solar Marketing, LLC	Delaware
Capital Dynamics US Solar AIV-E, LLC	Delaware
CD US Solar MT 3, LLC	Delaware

CD US Solar PO 3, LLC	Delaware
Capital Dynamics US Solar AIV-G, LLC	Delaware
CD US Solar Sponsor, LLC	Delaware
CD US Solar Developer, LLC	Delaware
TerraForm REC ACQ Master Holdco, LLC	Delaware
TerraForm REC ACQ Holdings, LLC	Delaware
TerraForm REC Holdings, LLC	Delaware
TerraForm REC Operating, LLC	Delaware
TerraForm Solar XVII ACQ Master Holdco, LLC	Delaware
TerraForm Solar XVII ACQ Holdings, LLC	Delaware
TerraForm Raptor 1 Holdings, LLC	Delaware
TerraForm Raptor 1, LLC	Delaware
TerraForm Raptor XV Holdings, LLC	Delaware
SunE Solar XV Holdco, LLC	Delaware
SunE Solar XV Lessor Parent, LLC	Delaware
SunE Solar XV Lessor, LLC	Delaware
TerraForm Raptor XVI Holdings, LLC	Delaware
SunE Solar XVI Manager, LLC	Delaware
SunE Solar XVI Holdings, LLC	Delaware
SunE Solar XVI Lessor, LLC	Delaware
TerraForm Solar XVII Manager, LLC	Delaware
TerraForm Solar XVII, LLC	Delaware
SunE 29 Palms, LLC	Delaware
SunE CasimirES, LLC	Delaware
SunE DB10, LLC	Delaware
SunE DB11, LLC	Delaware
SunE DB12, LLC	Delaware
SunE DB15, LLC	Delaware
SunE DB17, LLC	Delaware
SunE DB18, LLC	Delaware
SunE DB20, LLC	Delaware
SunE DB24, LLC	Delaware
SunE DB33, LLC	Delaware
SunE DB34, LLC	Delaware
SunE DB36, LLC	Delaware
SunE DG3, LLC	Delaware
SunE DG6, LLC	Delaware
SunE DG12, LLC	Delaware
SunE DG13, LLC	Delaware
SunE DG14, LLC	Delaware
SunE DG15, LLC	Delaware
SunE DG16, LLC	Delaware

SunE DG17, LLC	Delaware
SunE DG18, LLC	Delaware
SunE EshlemanHall, LLC	Delaware
SunE SEM 2, LLC	Delaware
SunE SEM 3, LLC	Delaware
BWC Origination 10, LLC	Delaware
SunE Solar XVII Project1, LLC	Delaware
SunE Solar XVII Project2, LLC	Delaware
SunE Solar XVII Project3, LLC	Delaware
TerraForm First Wind ACQ Master Holdco, LLC	Delaware
TerraForm First Wind ACQ, LLC	Delaware
First Wind Operating Company, LLC	Delaware
TerraForm Osprey I Holdings, LLC	Delaware
TerraForm Osprey I, LLC	Delaware
Rollins Holdings, LLC	Delaware
Evergreen Wind Power III, LLC	Delaware
Hawaii Holdings, LLC	Delaware
Kaheawa Wind Power II, LLC	Delaware
TerraForm KWP Investor Holdings, LLC	Delaware
KWP Upwind Holdings LLC	Delaware
First Wind HWP Holdings, LLC	Delaware
Hawaii Wind Partners, LLC	Delaware
Hawaiian Island Holdings, LLC	Delaware
First Wind Kahuku Holdings, LLC	Delaware
Kahuku Holdings, LLC	Delaware
Kahuku Wind Power, LLC	Delaware
Hawaii Wind Partners II, LLC	Delaware
Kaheawa Wind Power, LLC	Delaware
First Wind Northeast Company, LLC	Delaware
Northeast Wind Partners II, LLC	Delaware
Northeast Wind Capital Holdings, LLC	Delaware
Northeast Wind Capital II, LLC	Delaware
Maine Wind Partners II, LLC	Delaware
Maine Wind Partners, LLC	Delaware
Evergreen Wind Power, LLC	Delaware
Stetson Wind Holdings Company, LLC	Delaware
Stetson Holdings, LLC	Delaware
Stetson Wind II, LLC	Delaware
Evergreen Gen Lead, LLC	Delaware
First Wind Blue Sky East Holdings, LLC	Delaware
Blue Sky East Holdings, LLC	Delaware
Blue Sky East, LLC	Delaware

Sheffield Wind Holdings, LLC	Delaware
Sheffield Holdings, LLC	Delaware
Vermont Wind, LLC	Delaware
CSSW Cohocton Holdings, LLC	Delaware
New York Wind, LLC	Delaware
Canandaigua Power Partners, LLC	Delaware
Canandaigua Power Partners II, LLC	Delaware
CSSW Steel Winds Holdings, LLC	Delaware
Huron Holdings, LLC	Delaware
Erie Wind, LLC	Delaware
Niagara Wind Power, LLC	Delaware
FW Mass PV Portfolio, LLC	Delaware
FWPV Capital, LLC	Delaware
FWPV Holdings, LLC	Delaware
FWPV, LLC	Delaware
Mass Solar 1 Holdings, LLC	Delaware
Mass Solar 1, LLC	Delaware
Mass Midstate Solar 1, LLC	Delaware
Mass Midstate Solar 2, LLC	Delaware
Mass Midstate Solar 3, LLC	Delaware
Millbury Solar, LLC	Delaware
TerraForm Thor ACQ Master Holdco, LLC	Delaware
TerraForm Thor ACQ Holdings, LLC	Delaware
TerraForm Private Holdings II, LLC	Delaware
TerraForm Private II, LLC	Delaware
TerraForm Private Operating II, LLC	Delaware
FW Panhandle Portfolio II, LLC	Delaware
First Wind Panhandle Holdings II, LLC	Delaware
First Wind South Plains Portfolio, LLC	Delaware
First Wind Texas Holdings II, LLC	Delaware
South Plains Wind Energy, LLC	Delaware
TerraForm IWG Acquisition Holdings, LLC	Delaware
Rattlesnake Wind I Class B Holdings LLC	Delaware
Rattlesnake Wind I Holdings LLC	Delaware
Rattlesnake Wind I LLC	Delaware
TerraForm IWG Acquisition Ultimate Holdings II, LLC	Delaware
TerraForm IWG Acquisition Intermediate Holdings II, LLC	Delaware
TerraForm IWG Acquisition Holdings II Parent, LLC	Delaware
TerraForm IWG Acquisition Holdings II, LLC	Delaware
Bishop Hill Class B Holdings LLC	Delaware
Bishop Hill Holdings LLC	Delaware
Bishop Hill Energy LLC	Delaware

TerraForm IWG Acquisition Holdings III, LLC	Delaware
California Ridge Class B Holdings LLC	Delaware
California Ridge Holdings LLC	Delaware
California Ridge Wind Energy LLC	Delaware
Invenergy Prairie Breeze Holdings LLC	Delaware
Prairie Breeze Class B Holdings LLC	Delaware
Prairie Breeze Holdings LLC	Delaware
Prairie Breeze Wind Energy LLC	Delaware
TerraForm IWG Ontario Holdings Grandparent, LLC	Delaware
TerraForm IWG Ontario Holdings Parent, LLC	Delaware
TerraForm IWG Ontario Holdings, LLC	Delaware
TerraForm Utility Solar XIX Pledgor, LLC	Delaware
TerraForm Utility Solar XIX Holdings, LLC	Delaware
TerraForm Utility Solar XIX Manager, LLC	Delaware
TerraForm Utility Solar XIX, LLC	Delaware
Beryl Solar, LLC	Delaware
Buckhorn Solar, LLC	Delaware
Cedar Valley Solar, LLC	Delaware
Granite Peak Solar, LLC	Delaware
Greenville Solar, LLC	Delaware
Laho Solar, LLC	Delaware
LKL BLBD, LLC	Delaware
Milford Flat Solar, LLC	Delaware
River Mountains Solar, LLC	Delaware
SunE DB APNL, LLC	Delaware
TerraForm Falcon 1 Holdings, LLC	Delaware
TerraForm Falcon 1, LLC	Delaware
SunE B9 Holdings, LLC	Delaware
CALRENEW-1 LLC	Delaware
TerraForm Falcon 2 Holdings, LLC	Delaware
TerraForm Falcon 2, LLC	Delaware
CD US Solar MT 1, LLC	Delaware
SunE Alamosa1 Holdings, LLC	Delaware
SunE Alamosa1 LLC	Delaware
OL’s SunE Alamosa1 Trust	Delaware
SunEdison Yieldco ACQ10, LLC	Delaware
TerraForm Tinkham Hill Expansion, LLC	Delaware
BWC Pine Island Brook, LLC	Delaware
TerraForm Dairyland Acquisitions, LLC	Delaware
Sunny Templeton, LLC	Delaware
Camden Solar Center, LLC	New Jersey
Integrys CA Solar, LLC	Delaware

Integrys Solar, LLC	Delaware
Gilbert Solar Facility I, LLC	Delaware
INDU Solar Holdings, LLC	Delaware
Berkley East Solar LLC	Delaware
ISH Solar AZ, LLC	Delaware
ISH Solar Beach, LLC	Delaware
ISH Solar CA, LLC	Delaware
ISH Solar Central, LLC	Delaware
ISH Solar Hospitals, LLC	Delaware
ISH Solar Mouth, LLC	Delaware
SEC BESD Solar One, LLC	Delaware
SEC Bellefonte SD Solar One, LLC	Delaware
Sterling Solar LLC	Delaware
Solar Hold 2008–1, LLC	Delaware
Integrys NJ Solar, LLC	Delaware
Solar Star California II, LLC	Delaware
Soltage – ADC 630 Jamesburg, LLC	Delaware
Soltage–MAZ 700 Tinton Falls, LLC	Delaware
Soltage – PLG 500 Milford, LLC	Delaware
Solar Star New Jersey VI, LLC	Delaware
ISH Solar Grin, LLC	Delaware
Integrys MA Solar, LLC	Delaware
TerraForm Energy Services Holdings, LLC	Delaware
TerraForm Canada Energy Services, Inc.	British Columbia
TerraForm US Energy Services, LLC	Delaware
TerraForm Italy LDV Holdings, LLC	Delaware
TerraForm Japan Holdco, LLC	Delaware
TerraForm Japan Holdco G.K.	Japan
TerraForm Power Holdings B.V.	Netherlands
TerraForm Power Finance B.V.	Netherlands
TerraForm PR Holdings 1, LLC	Delaware
TerraForm Solar IX Holdings, LLC	Delaware
TerraForm Solar XVIII ACQ Holdings, LLC	Delaware
TerraForm Solar XVIII Manager, LLC	Delaware
TerraForm Solar XVIII, LLC	Delaware
SunE DB3, LLC	Delaware
SunE DB8, LLC	Delaware
SunE DB27, LLC	Delaware
SunE DB42, LLC	Delaware
SunE DB43, LLC	Delaware
SunE DB44, LLC	Delaware
SunE DB45, LLC	Delaware

SunE DG1, LLC	Delaware
SunE DG2, LLC	Delaware
SunE DG8, LLC	Delaware
SunE DG25, LLC	Delaware
SunE IM Pflugerville, LLC	Delaware
SunE HARD Mission Hills, LLC	Delaware
SunE HH Blue Mountain, LLC	Delaware
SunE HH Buchanan, LLC	Delaware
SunE HH Frank Lindsey, LLC	Delaware
SunE HH Furnace Woods, LLC	Delaware
SunE HH Hudson High, LLC	Delaware
Oak Leaf Solar V LLC	Delaware
Water Street Solar 1, LLC	Delaware
TerraForm MP Holdings, LLC	Delaware
TerraForm MP Solar, LLC	Delaware
TerraForm Ontario Solar Holdings, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:   

(1)Registration Statement (Form S-1 No. 333-221593) of Terraform Power, Inc.,

(2)Registration Statement (Form S-8 No. 333-205337) of Terraform Power, Inc., and

(3)Registration Statement (Form S-3 No. 333-234076) of Terraform Power, Inc.;

of our reports dated March 17, 2020, with respect to the consolidated financial statements of Terraform Power, Inc. and the effectiveness of internal control over financial reporting of Terraform Power, Inc. included in this Annual Report (Form 10-K) of Terraform Power, Inc. for the year ended December 31, 2019.

/s/ Ernst & Young LLP

New York, New York

March 17, 2020

EX-23.2

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Terraform Power, Inc.:

We consent to the incorporation by reference in the registration statements on Form S-8 (No. 333-205337) and on Form S-1 (No. 333-223753) of TerraForm Power, Inc. of our report dated March 7, 2018, except for the fourth paragraph in Note 18, as to which the date is March 15, 2019, with respect to the consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows of Terraform Power, Inc. and subsidiaries for the year ended December 31, 2017, and the related notes, which report appears in the December 31, 2018 annual report on Form 10-K of TerraForm Power, Inc.

/s/ KPMG LLP

McLean, Virginia

March 17, 2020

EX-31.1

Exhibit 31.1

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, John Stinebaugh, Chief Executive Officer, certify that:

1  I have reviewed this Annual Report on Form 10-K of TerraForm Power, Inc.;

2  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision; to ensure that material information relating to the registrant, including its consolidated subsidiaries is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 17, 2020

By:	/s/ JOHN STINEBAUGH
Name:	John Stinebaugh
Title:	Chief Executive Officer
	(Principal executive officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Michael Tebbutt, Chief Financial Officer, certify that:

1  I have reviewed this Annual Report on Form 10-K of TerraForm Power, Inc.;

2  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision; to ensure that material information relating to the registrant, including its consolidated subsidiaries is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 17, 2020

By:	/s/ MICHAEL TEBBUTT
Name:	Michael Tebbutt
Title:	Chief Financial Officer
	(Principal financial officer and principal accounting officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of TerraForm Power, Inc. (the “Company”) for the year ended December 31, 2019 filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, John Stinebaugh, Chief Executive Officer of the Company, and Michael Tebbutt, Chief Financial Officer of the Company, certify, to the best of our knowledge, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 17, 2020

By:	/s/ JOHN STINEBAUGH
Name:	John Stinebaugh
Title:	Chief Executive Officer
	(Principal executive officer)

Date: March 17, 2020

By:	/s/ MICHAEL TEBBUTT
Name:	Michael Tebbutt
Title:	Chief Financial Officer
	(Principal financial officer and principal accounting officer)

XML

Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Accumulated Other Comprehensive Income

ACCUMULATED OTHER COMPREHENSIVE INCOME

The following table presents the changes in each component of accumulated other comprehensive (loss) income, net of tax:

(In thousands)	Foreign Currency Translation Adjustments		Hedging Activities1		Accumulated Other Comprehensive Income
Balance as of December 31, 2016	$	(22,133)	$	45,045	$	22,912
Net unrealized gain arising during the period (net of tax expense of $3,238 and $2,428, respectively)	10,300		17,612		27,912
Reclassification of net realized loss (gain) into earnings (net of tax benefit of $8,858 and tax expense of $443, respectively)2	14,741		(2,247)		12,494
Other comprehensive income	25,041		15,365		40,406
Accumulated other comprehensive income	2,908		60,410		63,318
Less: Other comprehensive income attributable to non-controlling interests	8,665		5,992		14,657
Plus: Reallocation from non-controlling interests as a result of SunEdison exchange3	(7,655)		7,012		(643)
Balance as of December 31, 2017	(13,412)		61,430		48,018
Cumulative-effect adjustment (net of tax expense of $1,579)4	—		(4,164)		(4,164)
Cumulative-effect adjustment (net of tax expense of $9,357)5	14,524		(5,156)		9,368
Net unrealized (loss) gain arising during the year (net of tax expense of $3,891 and $3,729, respectively)	(9,517)		1,166		(8,351)
Reclassification of net realized gain into earnings (net of zero and $4,938 tax benefit, respectively)	—		(5,410)		(5,410)
Other comprehensive income	(9,517)		(4,244)		(13,761)
Accumulated other comprehensive income	(8,405)		47,866		39,461
Less: Other comprehensive income attributable to non-controlling interests	—		(777)		(777)
Balance as of December 31, 2018	(8,405)		48,643		40,238
Net unrealized gain (loss) arising during the period (net of zero and $978 tax benefit, respectively)	15,652		(42,290)		(26,638)
Reclassification of net realized gain into earnings (net of zero tax impact)	—		(2,579)		(2,579)
Other comprehensive income (loss)	15,652		(44,869)		(29,217)
Accumulated other comprehensive income	7,247		3,774		11,021
Less: Other comprehensive income attributable to non-controlling interests	—		(624)		(624)
Balance as of December 31, 2019	$	7,247	$	4,398	$	11,645

———

(1)See Note 12. Derivatives for additional breakout of hedging gains and losses for interest rate swaps and commodity contracts in a cash flow hedge relationship and the foreign currency contracts designated as hedges of net investments.

(2)The foreign currency translation adjustment amount represents the reclassification of the accumulated foreign currency translation loss for the U.K. Portfolio, as the Company’s sale of this portfolio closed in the second quarter of 2017. The pre-tax amount of $23.6 million was recognized within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

(3)Represents reclassification of accumulated comprehensive (losses) income previously attributed to SunEdison’s non-controlling interest in Terra LLC from non-controlling interests to AOCI as of October 16, 2017, as a result of SunEdison’s exchange of its Class B units in Terra LLC for Class A shares of TerraForm Power as discussed in Note 18. Non-Controlling Interests.

(4)Represents the cumulative-effect adjustment related to the early adoption of ASU 2017-12. See Note 2. Summary of Significant Accounting Policies for additional details.

(5)Represents the cumulative-effect adjustment of deferred taxes stranded in AOCI resulting from the early adoption of ASU No. 2018-02 See Note 2. Summary of Significant Accounting Policies.

XML

Variable Interest Entities

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITIES

The Company assesses entities for consolidation in accordance with ASC 810. The Company consolidates VIEs in renewable energy facilities when the Company is determined to be the primary beneficiary. VIEs are entities that lack one or more of the characteristics of a VOE. The Company has a controlling financial interest in a VIE when its variable interest(s) provide it with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The VIEs own and operate renewable energy facilities in order to generate contracted cash flows. The VIEs were funded through a combination of equity contributions from the owners and non-recourse project-level debt.

The carrying amounts and classification of the consolidated assets and liabilities of the VIEs included in the Company’s consolidated balance sheets were as follows:

	As of December 31,
(In thousands)	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	44,083	$	69,896
Restricted cash	10,562		10,428
Accounts receivable, net	39,804		31,740
Derivative assets, current	2,461		2,038
Prepaid expenses	3,466		3,194
Other current assets	21,228		16,761
Total current assets	121,604		134,057
Renewable energy facilities, net	3,188,508		3,064,675
Intangible assets, net	690,594		751,377
Restricted Cash	4,454		12,140
Derivative assets	56,852		78,916
Other assets	7,061		2,441
Total assets	$	4,069,073	$	4,043,606
Liabilities
Current liabilities:
Current portion of long-term debt and financing lease obligations	$	55,089	$	64,251
Accounts payable, accrued expenses and other current liabilities	42,685		55,996
Derivative liabilities, current	449		543
Total current liabilities	98,223		120,790
Long-term debt and financing lease obligations, less current portion	932,862		885,760
Operating lease obligations, less current portion	138,816		—
Asset retirement obligations	116,159		86,457
Derivative liabilities	894		3,558
Other liabilities	41,813		39,014
Total liabilities	$	1,328,767	$	1,135,579

The amounts shown in the table above exclude intercompany balances that are eliminated upon consolidation. All the assets in the table above are restricted for settlement of the VIE obligations, and all the liabilities in the table above can only be settled by using VIE resources.

XML

Income Taxes - Schedule of Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Income tax benefit at U.S. federal statutory rate	21.00%	21.00%	35.00%
Increase (reduction) in income taxes:
State income taxes, net of U.S. federal benefit	5.90%	5.00%	4.00%
Foreign operations	(2.00%)	(0.50%)	8.70%
Non-controlling interests	(8.00%)	(25.90%)	(9.40%)
Permanent differences	(0.20%)	(1.60%)	0.00%
Tax Act rate change impact	0.00%	0.00%	2.00%
Return to provision	0.00%	0.00%	2.80%
Change in valuation allowance	(22.40%)	7.80%	(34.10%)
Other	(0.40%)	1.60%	0.00%
Effective tax rate	(6.10%)	7.40%	9.00%

XML

Acquisitions and Divestitures - Divestitures (Details) $ in Thousands, £ in Millions			3 Months Ended	12 Months Ended
	Dec. 20, 2019 USD ($) business MW	May 11, 2017 USD ($)	Dec. 31, 2019 USD ($) business	Dec. 31, 2019 USD ($) business	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 MW	May 11, 2017 GBP (£) power_plant MW	May 11, 2017 USD ($) power_plant MW
Business Acquisition [Line Items]
Gain on sale of renewable energy facilities				$ 2,252	$ 0	$ 37,116
Number of operating projects | business			2	2
Secured Debt
Business Acquisition [Line Items]
Prepayment for term loan		$ 30,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Capacity of power (MW) | MW							0.3
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Distributed Generation Facilities
Business Acquisition [Line Items]
Number of assets sold | business	6
Capacity of power (MW) | MW	6.0
Proceeds from sale	$ 9,500
Gain on sale of renewable energy facilities	$ 2,300		$ 2,300
Number of operating projects | business	6
Disposal Group, Disposed of by Sale, Not Discontinued Operations | U.K. Portfolio
Business Acquisition [Line Items]
Capacity of power (MW) | MW								365.0	365.0
Number of operating projects | power_plant								24	24
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Sale to Vortex Solar
Business Acquisition [Line Items]
Capacity of power (MW) | MW								11.1	11.1
Proceeds from sale									$ 214,100
Number of operating projects | power_plant								1	1
Transaction expenses		$ 3,900
Cash and cash equivalents disposed of									$ 14,800
Restricted cash disposed of									$ 21,800
Reduction in debt | £								£ 301
Gain on sale						$ 37,100

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Acquisitions and Divestitures - Saeta Acquisition Narrative (Details) $ in Thousands		12 Months Ended
	Jun. 12, 2018 USD ($) MW	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jun. 12, 2019 USD ($)	Jul. 02, 2018	Jun. 08, 2018	Feb. 07, 2018 € / shares MW
Business Acquisition [Line Items]
Proceeds from issuance of common stock		$ 298,767	$ 650,000	$ 0
Proceeds from the Sponsor Line - affiliate		0	86,000	0
Revolver draws		492,500	679,000	$ 265,000
Revolving Credit Facility | Sponsor Line Agreement
Business Acquisition [Line Items]
Proceeds from the Sponsor Line - affiliate	$ 30,000
Revolving Credit Facility | New Revolver
Business Acquisition [Line Items]
Revolver draws	$ 359,000
Saeta Yield
Business Acquisition [Line Items]
Voting interests acquired	95.28%							100.00%
Price per share (euros per share) | € / shares								€ 12.20
Percentage of voting interests accepted to be acquired							95.00%
Consideration transferred	$ 1,120,000
Project-level debt assumed	$ 1,906,831				$ 1,894,426
Remaining voting interest to be acquired	4.72%					4.72%
Consideration to be transferred	$ 54,600
Proceeds from issuance of common stock	650,000
Existing liquidity	471,000
Payments to acquire business	82,000
Pro forma operating revenues		407,100	221,200
Pro forma net income		$ 57,600	$ 38,200
Saeta Yield | Sponsor Line Agreement
Business Acquisition [Line Items]
Proceeds from additional draw on Sponsor Line	$ 54,600
Saeta Yield | Regulated Solar and Wind
Business Acquisition [Line Items]
Capacity of power (MW) | MW	1,000							1,000
Saeta Yield | Wind
Business Acquisition [Line Items]
Capacity of power (MW) | MW	778							250
Saeta Yield | Solar
Business Acquisition [Line Items]
Capacity of power (MW) | MW	250							778

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Other Financial Information- Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Taxes receivable	$ 14,435	$ 18,798
Indemnity receivable	15,229	15,348
Spare parts inventory	266	7,562
Purchased solar renewable energy credits	5,019	0
Due from financial institutions	6,299	0
Due from service provider	8,212	0
Note receivable from public utility company	4,187	1,027
Miscellaneous	4,035	9,298
Total other current assets	$ 57,682	$ 52,033

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Long-Term Debt - Minimum Lease Payments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Finance lease obiligations	$ 59,533
2020	3,091
2021	3,171
2022	3,126
2023	4,310
2024	2,933
Thereafter	42,902
Total	59,533
Debt Instrument [Line Items]
Default amount	159,300	$ 166,400
Finance Lease Obligations
Debt Instrument [Line Items]
Default amount	$ 9,800

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Stockholders' Equity - Schedule of Changes in Common Stock Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands				3 Months Ended	12 Months Ended
	Oct. 08, 2019	Aug. 03, 2018	Jun. 11, 2018	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance (in shares)					209,142,000	148,086,000
Issued of Common Stock in public offering (in shares)					14,907,000	0
New issuances of common stock (in shares)		80,084			2,982,000	61,056,000
Stock-based compensation (in shares)					13,000	0
Purchase of treasury stock (in shares)				543,265	543,000	0
Ending balance (in shares)				226,501,000	226,501,000	209,142,000	148,086,000
Proceeds from issuance of common stock					$ 298,767	$ 650,000	$ 0
Public Offering
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issued of Common Stock in public offering (in shares)	14,907,573
Sale of stock, price per share (in usd per share)	$ 16.77
Proceeds from issuance of common stock	$ 250,000
Private Placement
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issued of Common Stock in public offering (in shares)	2,981,514		60,975,609
Sale of stock, price per share (in usd per share)	$ 16.77		$ 10.66
Proceeds from issuance of common stock	$ 50,000		$ 650,000

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Long-Term Debt - Sponsor Line Agreement (Details) - Revolving Credit Facility - USD ($)		12 Months Ended
	Oct. 16, 2017	Dec. 31, 2018	Oct. 08, 2019	Feb. 06, 2018	Oct. 17, 2017
Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 800,000,000.00
Sponsor Line Agreement
Debt Instrument [Line Items]
Revolver repayments		$ 86,000,000.0
Sponsor Line Agreement | Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 500,000,000.0
Percentage of capital stock	10000.00%
Sponsor Line Agreement | Line of Credit | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	3.00%
Revolver | Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 600,000,000.0	$ 450,000,000.0
Revolver | Line of Credit | LIBOR
Debt Instrument [Line Items]
Standby fee	50.00%

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Acquisitions and Divestitures - WGL Acquisition and X-Elio PV Acquisition (Details) € in Millions				3 Months Ended
	Dec. 18, 2019 USD ($) MW	Dec. 18, 2019 EUR (€)	Sep. 26, 2019 USD ($) MW	Dec. 31, 2019 USD ($) MW	Sep. 25, 2019 USD ($) MW	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Escrow Deposit				$ 24,831,000		$ 0
Bridge Facility
Business Acquisition [Line Items]
Capacity of power (MW) | MW					320
Face amount of debt instrument				$ 474,600,000	$ 475,000,000.0
X-Elio PV Acquisition
Business Acquisition [Line Items]
Capacity of power (MW) | MW	45			15.1
Asset acquisition, consideration transferred	$ 71,100,000	€ 63.8
Asset acquisition, renewable energy facilities	186,500,000
X-Elio PV Acquisition | Licensing agreements
Business Acquisition [Line Items]
Finite-lived intangible assets acquired	$ 54,800,000
X-Elio PV Acquisition | Solar Power Facilities
Business Acquisition [Line Items]
Remaining regulatory life	21 years	21 years
WGL Acquisition
Business Acquisition [Line Items]
Capacity of power (MW) | MW			320
Consideration transferred			$ 720,000,000.0
Consideration transferred, working capital			15,100,000
Nameplate capacity, delayed project | MW				11.6
Escrow Deposit			24,831,000
Pro forma operating revenues				$ 13,800,000
Pro forma net income				$ 100,000
WGL Acquisition | Bridge Facility
Business Acquisition [Line Items]
Face amount of debt instrument			$ 475,000,000.0

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Subsequent Events (Details) $ / shares in Units, € in Millions, $ in Millions					3 Months Ended									12 Months Ended
	Mar. 16, 2020 $ / shares	Feb. 11, 2020 EUR (€) business MW	Feb. 11, 2020 USD ($) business MW	Oct. 06, 2017 $ / shares	Dec. 31, 2019 business $ / shares	Sep. 30, 2019 $ / shares	Jun. 30, 2019 $ / shares	Mar. 31, 2019 $ / shares	Dec. 31, 2018 $ / shares	Sep. 30, 2018 $ / shares	Jun. 30, 2018 $ / shares	Mar. 31, 2018 $ / shares	Dec. 31, 2017 $ / shares	Dec. 31, 2019 business $ / shares	Dec. 31, 2018 $ / shares	Dec. 31, 2017 $ / shares	Mar. 17, 2020	Jan. 11, 2020
Subsequent Event [Line Items]
Number of operating projects | business					2									2
Dividends declared (usd per share) | $ / shares				$ 1.94	$ 0.2014	$ 0.2014	$ 0.2014	$ 0.2014	$ 0.19	$ 0.19	$ 0.19	$ 0.19	$ 1.94	$ 0.8056	$ 0.7600	$ 1.9400
Affiliates of Brookfield | TerraForm Power
Subsequent Event [Line Items]
Ownership percentage held					62.00%									62.00%
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (usd per share) | $ / shares	$ 0.2014
Subsequent Event | Solar Power Facilities
Subsequent Event [Line Items]
Capacity of power (MW) | MW		100	100
Number of operating projects | business		2	2
Purchase price net of cash acquired		€ 116.8	$ 127.5
Remaining regulatory life		19 years	19 years
Subsequent Event | Brookfield Renewable | Common Stock | TerraForm Power | Common Class A
Subsequent Event [Line Items]
Proposal to acquire shares of Common Stock for consideration of shares equivalent	0.381
Subsequent Event | Brookfield Renewable | TerraForm Power
Subsequent Event [Line Items]
Ownership percentage, indirect																	30.00%	30.00%

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The activity on asset retirement obligations for the years ended December 31, 2019, 2018 and 2017 was as follows:

	Year Ended December 31,
(In thousands)	2019		2018		2017
Balance as of January 1	$	212,657	$	154,515	$	148,575
Assumed through acquisition	33,143		68,441		—
Accretion expense	15,475		6,866		8,578
Extinguishment upon divestitures	(864)		—		(3,238)
Adjustment related to change in accretion period1	27,917		(15,734)		—
Other	—		843		—
Currency translation adjustments	(1,040)		(2,274)		600
Balance as of December 31	$	287,288	$	212,657	$	154,515

————

(1)Represents corrections related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement. The correction during the year ended December 31, 2019, recorded in the third quarter, resulted in $27.9 million increase in the carrying amounts of asset retirement obligations and the corresponding renewable energy facilities. The Company also recorded an adjustment to increase the previously reported accretion and depreciation expense by $3.3 million and $3.7 million, respectively, as a result of this change. The Company had recorded an adjustment during the fourth quarter of 2018, which resulted in a $15.7 million reduction in the Company’s asset retirement obligations and the corresponding renewable energy facilities’ carrying amounts as of December 31, 2018. The Company also recorded an adjustment during the fourth quarter of 2018 to reduce previously reported accretion and depreciation expense by $6.3 million as a result of this change. The Company evaluated these adjustments and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company’s consolidated financial statements for any prior period.

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Segment Reporting - Long-Lived Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	$ 9,326,705	$ 8,586,983
Current assets	553,347	501,185
Other non-current assets	178,584	242,186
Total assets	10,058,636	9,330,354	$ 6,387,021
United States (including Puerto Rico)
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	5,722,092	5,030,483
Canada
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	366,862	362,829
Spain
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	2,574,546	2,503,420
Portugal
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	229,629	251,053
United Kingdom
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	17,289	13,183
URUGUAY
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	261,189	264,798
Chile
Segment Reporting, Asset Reconciling Item [Line Items]
Total long-lived assets, net	$ 155,098	$ 161,217

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Related Parties - Net SunEdison Investment (Details) - SunEdison - Affiliated Entity $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($)
Related Party Transaction [Line Items]
Net SunEdison investment	$ 9,768
General and administrative expenses - affiliate
Related Party Transaction [Line Items]
Net SunEdison investment	6,154
TerraForm Power, Inc. equity awards distributed to SunEdison
Related Party Transaction [Line Items]
Net SunEdison investment	(3,372)
Other
Related Party Transaction [Line Items]
Net SunEdison investment	$ 6,986

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Financial Instruments Measured at Fair Value on Recurring Basis

The following table summarizes the financial instruments measured at fair value on a recurring basis classified in the fair value hierarchy (Level 1, 2 or 3) based on the inputs used for valuation in the consolidated balance sheets:

	As of December 31, 2019								As of December 31, 2018
(In thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	809	$	—	$	809	$	—	$	7,296	$	—	$	7,296
Commodity contracts	—		5,859		59,312		65,171		—		12,952		79,652		92,604
Foreign currency contracts	—		7,556		—		7,556		—		5,455		—		5,455
Total derivative assets	$	—	$	14,224	$	59,312	$	73,536	$	—	$	25,703	$	79,652	$	105,355
Liabilities
Interest rate swaps	$	—	$	134,986	$	—	$	134,986	$	—	$	126,100	$	—	$	126,100
Foreign currency contracts	—		377		—		377		—		3,307		—		3,307
Total derivative liabilities	$	—	$	135,363	$	—	$	135,363	$	—	$	129,407	$	—	$	129,407

Changes in the Fair Value of Derivative Instruments Classified as Level 3

The following table reconciles the changes in the fair value of derivative instruments classified as Level 3 in the fair value hierarchy for the years ended December 31, 2019 and 2018:

	Year Ended December 31,
(In thousands)	2019		2018
Balance as of January 1	$	79,652	$	80,268
Realized and unrealized (losses) gains:
Included in other comprehensive loss	(8,920)		(4,736)
Included in operating revenues, net	(12,441)		6,244
Net settlements	1,021		(2,124)
Balance as of December 31	$	59,312	$	79,652

Significant Unobservable Inputs Used in the Valuation of the Commodity Contracts

The significant unobservable inputs used in the valuation of the Company’s commodity contracts classified as Level 3 in the fair value hierarchy as of December 31, 2019 are as follows:

(In thousands, except range)	Fair Value as of December 31, 2019
Transaction Type	Assets		Liabilities		Valuation Technique	Unobservable Inputs as of December 31, 2019
Commodity contracts - power	$	59,312	$	—	Option model	Volatilities	14.2%
							Range
					Discounted cash flow	Forward price (per MWh)	$	6.30	-	$	169.30

Sensitivity of Fair Value Measurements

The sensitivity of the Company’s fair value measurements to increases (decreases) in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Impact on Fair Value Measurement
Increase (decrease) in forward price	Forward sale	Decrease (increase)
Increase (decrease) in implied volatilities	Purchase option	Increase (decrease)

Carrying Amount and Estimated Fair Value of Long-term Debt

The carrying amount and estimated fair value of the Company’s long-term debt as of December 31, 2019 and 2018 was as follows:

	As of December 31, 2019				As of December 31, 2018
(In thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	6,235,382	$	6,512,188	$	5,761,845	$	5,789,702

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Acquisitions and Divestitures - Residential Portfolio Sale (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MW
Enfinity Colorado DHA 1
Business Acquisition [Line Items]
Membership interest sold	100.00%
Capacity of power (MW) | MW	2.5
TerraForm Resi Manager
Business Acquisition [Line Items]
Membership interest sold	100.00%
Capacity of power (MW) | MW	8.9
TerraForm Resi Manager and Enfinity Colorado DHA 1
Business Acquisition [Line Items]
Proceeds from sale	$ 7.1
Cash and cash equivalents disposed of	0.6
Restricted cash disposed of	$ 0.8

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Intangible Assets, Net And Goodwill - Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Roll Forward]
Balance, beginning	$ 120,553	$ 0
Goodwill resulting from business combinations		115,381
Adjustments during the period	10,196	7,726
Foreign exchange differences	(2,797)	(2,554)
Balance, ending	$ 127,952	$ 120,553

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Fair Value of Financial Instruments - Recurring Basis Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets and Liabilities
Assets	$ 74,949	$ 106,556
Liabilities	136,776	130,608
Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	73,536	105,355
Liabilities	135,363	129,407
Interest rate swaps | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	809	7,296
Liabilities	134,986	126,100
Commodity Price Swap [Member] | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	65,171	92,604
Foreign currency contracts | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	7,556	5,455
Liabilities	377	3,307
Level 1 | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	0	0
Liabilities	0	0
Level 1 | Interest rate swaps | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	0	0
Liabilities	0	0
Level 1 | Commodity Price Swap [Member] | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	0	0
Level 1 | Foreign currency contracts | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	0	0
Liabilities	0	0
Level 2 | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	14,224	25,703
Liabilities	135,363	129,407
Level 2 | Interest rate swaps | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	809	7,296
Liabilities	134,986	126,100
Level 2 | Commodity Price Swap [Member] | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	5,859	12,952
Level 2 | Foreign currency contracts | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	7,556	5,455
Liabilities	377	3,307
Level 3 | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	59,312	79,652
Liabilities	0	0
Level 3 | Interest rate swaps | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	0	0
Liabilities	0	0
Level 3 | Commodity Price Swap [Member] | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	59,312	79,652
Level 3 | Foreign currency contracts | Fair Value, Measurements, Recurring
Assets and Liabilities
Assets	0	0
Liabilities	$ 0	$ 0

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Leases - Maturity of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Leases [Abstract]
2020	$ 21,921
2021	21,828
2022	22,046
2023	22,220
2024	22,424
Thereafter	319,532
Total lease payments	429,971
Less: Imputed interest	(138,939)
Total	$ 291,032

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Derivatives - Narrative (Details) € in Thousands, $ in Thousands		3 Months Ended	12 Months Ended
	May 11, 2017 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 EUR (€)	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 EUR (€)
Derivative Instruments, Gain (Loss) [Line Items]
Collateral related to certain contracts			$ 0	$ 0
Gain expected to be reclassified			7,700,000
Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification of loss in AOCI	$ 400,000
Commodity contracts - power
Derivative Instruments, Gain (Loss) [Line Items]
Gains in AOCI of cash flow hedge		$ 44,300,000	30,900,000
Total gains on derivatives		$ 5,700,000
Gain expected to be reclassified			$ 1,600,000
Term of contract			8 years
Commodity contracts - power | Letter of Credit
Derivative Instruments, Gain (Loss) [Line Items]
Collateral related to certain contracts			$ 15,000,000.0	15,000,000.0
Interest rate swaps | Derivatives Designated as Hedging Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Notional amount			441,628,000	$ 357,797,000		$ 138,575	€ 310,721	$ 147,522	€ 0
Interest rate swaps | Gain on sale of renewable energy facilities
Derivative Instruments, Gain (Loss) [Line Items]
Gain on sale of renewable energy facilities					$ 23,400,000
Interest rate swaps | Secured Debt
Derivative Instruments, Gain (Loss) [Line Items]
Amount expected to be reclassified into earnings			$ (6,900,000)
Term of contract			19 years
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Notional amount						$ 94,000	€ 199,750	$ 81,600	€ 320,000
Foreign Currency Contracts | Minimum | Derivatives Designated as Hedging Instruments | Net Investment Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Maturity period of derivatives			3 months	3 months
Foreign Currency Contracts | Maximum | Derivatives Designated as Hedging Instruments | Net Investment Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Maturity period of derivatives			33 months	2 years

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Cash and Cash Equivalents - Schedule of Cash and Cash Equivalents and Restrict Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash and Cash Equivalents [Abstract]
Cash and cash equivalents	$ 237,480	$ 248,524	$ 128,087
Restricted cash	35,657	27,784	54,006
Restricted cash	76,363	116,501	42,694
Cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows	$ 349,500	$ 392,809	$ 224,787	$ 682,837

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Intangible Assets, Net And Goodwill - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Licensing agreements | Operating Revenues, net
Finite-Lived Intangible Assets [Line Items]
Net amortization	$ 66.9	$ 36.4
Contract-Based Intangible Assets | Operating Revenues, net
Finite-Lived Intangible Assets [Line Items]
Net amortization	39.9	38.8	$ 39.6
Contract-Based Intangible Assets | Depreciation, Accretion, and Amortization
Finite-Lived Intangible Assets [Line Items]
Net amortization	$ 26.2	$ 28.2	$ 25.5

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Long-Term Debt - Senior Notes (Details) - USD ($)							3 Months Ended	12 Months Ended
	Oct. 16, 2019	Dec. 12, 2017	Nov. 08, 2017	Jul. 17, 2015	Jun. 11, 2015	Jan. 28, 2015	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt							$ 6,228,936,000	$ 6,228,936,000
Loss on modification and extinguishment of debt, net							$ 31,100,000	26,953,000	$ 1,480,000	$ 81,099,000
Old Senior Notes due in 2023
Debt Instrument [Line Items]
Loss on modification and extinguishment of debt, net								0	0	72,277,000
Senior Notes due 2025
Debt Instrument [Line Items]
Loss on modification and extinguishment of debt, net								22,827,000	0	0
Term Loan
Debt Instrument [Line Items]
Loss on modification and extinguishment of debt, net								$ 4,006,000	1,480,000	$ 0
Secured Debt
Debt Instrument [Line Items]
Repurchase offer price percentage		101.00%
Secured Debt | 5.88% Senior Notes due 2023
Debt Instrument [Line Items]
Face amount of debt instrument						$ 800,000,000.0
Interest rate						5.88%
Proceeds from debt issuance as a percentage of face value						99.214%
Secured Debt | Old Senior Notes due in 2023
Debt Instrument [Line Items]
Face amount of debt instrument					$ 150,000,000.0
Interest rate					5.875%
Proceeds from debt issuance as a percentage of face value					101.50%
Long-term debt		$ 950,000,000.0
Senior Notes prepayment penalty		50,700,000							50,700,000
Loss on modification and extinguishment of debt, net									72,300,000
Unamortized deferred finance costs and discounts									21,600,000
Secured Debt | Senior Notes due 2025
Debt Instrument [Line Items]
Face amount of debt instrument				$ 300,000,000.0
Interest rate				612.50%
Proceeds from debt issuance as a percentage of face value				10000.00%
Long-term debt	$ 300,000,000.0
Senior Notes prepayment penalty	18,400,000
Secured Debt | Senior Notes due 2023
Debt Instrument [Line Items]
Face amount of debt instrument		$ 500,000,000.0
Interest rate		4.25%					425.00%	425.00%
Proceeds from debt issuance as a percentage of face value		100.00%
Secured Debt | Senior Notes due 2028
Debt Instrument [Line Items]
Face amount of debt instrument		$ 700,000,000.00
Interest rate		5.00%					500.00%	500.00%
Proceeds from debt issuance as a percentage of face value		100.00%
Secured Debt | Senior Notes due 2030
Debt Instrument [Line Items]
Face amount of debt instrument	$ 700,000,000.0
Interest rate	4.75%						475.00%	475.00%
Proceeds from debt issuance as a percentage of face value	100.00%
Secured Debt | Term Loan
Debt Instrument [Line Items]
Long-term debt	$ 343,900,000
Loss on modification and extinguishment of debt, net								$ 4,000,000.0	$ 1,500,000
Secured Debt | New Senior Notes due 2023 and Senior Notes due 2028
Debt Instrument [Line Items]
Repurchase offer price percentage		100.00%
Line of Credit | Revolver
Debt Instrument [Line Items]
Repayments of debt			$ 50,000,000.0
Line of Credit | Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Repayments of debt		$ 150,000,000.0

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Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Quarterly consolidated results of operations for the year ended December 31, 2019 were as follows:

(In thousands, except per share data)	Q1		Q2		Q31		Q42,3
Operating revenues, net	$	225,332	$	255,366	$	253,808	$	206,734
Operating income (loss)	29,104		54,928		40,365		(10,967)
Interest expense, net	86,287		71,041		89,393		51,421
Net loss	(36,057)		(16,827)		(62,313)		(91,388)
Net loss attributable to Class A common stockholders	(8,627)		(3,595)		(54,837)		(81,625)
Weighted average Class A common shares outstanding - basic and diluted	209,142		209,142		209,155		217,608
Net loss per weighted average Class A common share - basic and diluted	$	(0.04)	$	(0.02)	$	(0.26)	$	(0.38)

———

(1)During the third quarter of 2019, the Company recorded corrections related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement resulting in an increase in the previously reported accretion and depreciation expense by $3.3 million and $3.7 million, respectively, as a result of this change.

(2)As discussed in Note 3. Acquisitions and Divestitures, on September 26, 2019, the Company completed the WGL Acquisition representing an approximately 320 MW distributed generation portfolio of renewable energy facilities located in the United States. The below table presents selected financial information for the acquired entities as included in the Company’s results for the year ended December 31, 2019:

(In thousands)	Q1	Q2	Q3	Q4
Operating revenues, net	N/A	N/A	N/A	$	13,773
Operating income	N/A	N/A	N/A	166
Net income	N/A	N/A	N/A	80

(3)The fourth quarter of 2019 includes $31.1 million loss on modification and extinguishment of certain corporate and non-recourse project debt. See to Note 10. Long-term Debt for additional details.

(4)The fourth quarter of 2019 includes $2.3 million gain from the sale of six renewable energy facilities with a combined nameplate capacity of approximately 6 MW.

Quarterly consolidated results of operations for the year ended December 31, 2018, were as follows:

(In thousands, except per share data)	Q11,2		Q23,4		Q33,4		Q43,4,5
Operating revenues, net	$	127,547	$	179,888	$	246,042	$	213,093
Operating (loss) income	(22,049)		27,299		56,666		8,063
Interest expense, net	53,554		50,892		72,416		72,349
Net loss	(76,313)		(27,612)		(19,051)		(30,351)
Net income (loss) attributable to Class A common stockholders	82,796		(21,337)		(33,590)		(15,489)
Weighted average Class A common shares outstanding - basic	148,139		161,568		209,142		209,142
Weighted average Class A common shares outstanding - diluted	148,166		161,568		209,142		209,142
Net earnings (loss) per weighted average Class A common share - basic and diluted	$	0.56	$	(0.13)	$	(0.16)	$	(0.07)

———

(1)During the first quarter of 2018, the Company recognized an impairment charge of $15.2 million on renewable energy facilities due to the bankruptcy of a significant customer significant to a distributed generation project (see Note 6. Renewable Energy Facilities).

(2)During the first quarter of 2018, the Company recorded a reduction of $151.2 million to the non-controlling interests balance and a corresponding allocation of net loss attributable to non-controlling interests due to the change in the tax rate input in the HLBV methodology used by the Company. As a result of the reduction of the federal income tax rate from 35% to 21% as specified in the Tax Act, the Company allocated significantly lower amounts to certain non-controlling interests (i.e., tax equity investors) in order to achieve their contracted after-tax rate of return.

(3)As discussed in Note 3. Acquisitions and Divestitures, on June 12, 2018 the Company acquired approximately 95.28% of the outstanding shares of Saeta, a Spanish renewable power company with over 1,000 MW of wind and solar facilities (approximately 250 MW of solar and 778 MW of wind) located primarily in Spain. The Company acquired the remaining approximately 4.72% of the shares of Saeta on July 2, 2018. The below table presents selected financial information of Saeta as included in the Company’s results for the year ended December 31, 2018:

(In thousands)	Q1	Q2		Q3		Q4
Operating revenues, net	N/A	$	24,681	$	107,903	$	88,642
Operating income	N/A	10,055		37,212		21,824
Interest (income) expense, net	N/A	(4,114)		13,241		14,405
Net income	N/A	11,545		21,850		4,819

(4)During the second quarter of 2018, the Company discontinued hedge accounting for a certain long-dated commodity contract as it was no longer considered highly effective in offsetting the cash flows associated with the underlying risk being hedged. The gains (losses) in fair value on this commodity contract were recorded in earnings within operating revenues, net and amounted to $10.8 million, $0.9 million and $(5.3) million for the second, third and fourth quarters of 2018, respectively (see Note 12. Derivatives).

(5)During the fourth quarter of 2018, the Company recorded corrections related to the accretion period related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement resulting in a reduction in the previously reported accretion and depreciation expense by $6.3 million and $4.4 million, respectively, as a result of this change.

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Non-Controlling Interests - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Noncontrolling Interest [Abstract]
Reduction in noncontrolling interest	$ 151.2

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Related Parties - Narrative and Non Binding Proposal To Acquires All Outstanding Common Stock (Details)	Mar. 16, 2020	Mar. 17, 2020	Jan. 11, 2020	Dec. 31, 2019
Affiliates of Brookfield | TerraForm Power
Related Party Transaction [Line Items]
Voting securities				62.00%
Subsequent Event | Brookfield Renewable | TerraForm Power
Related Party Transaction [Line Items]
Ownership percentage, indirect		30.00%	30.00%
Subsequent Event | Common Stock | TerraForm Power | Common Class A | Brookfield Renewable
Related Party Transaction [Line Items]
Proposal to acquire shares of Common Stock for consideration of shares equivalent	0.381

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Related Parties (Tables)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table illustrates the detail of Net SunEdison investment for the year ended December 31, 2017, as reported in the consolidated statements of stockholders’ equity:

(in thousands)	Year ended December 31, 2017
General and administrative expenses - affiliate1	$	6,154
TerraForm Power, Inc. equity awards distributed to SunEdison2	(3,372)
Other3	6,986
Net SunEdison investment	$	9,768

———

(1)Represents costs incurred by SunEdison for services provided to the Company pursuant to the SunEdison MSA in excess of cash paid or payable to SunEdison, as well as stock-based compensation expense related to equity awards in the stock of SunEdison and TerraForm Global that was allocated to the Company (as discussed in Note 17. Stock-Based Compensation).

(2)Represents stock-based compensation cost related to equity awards in the Company’s stock which was allocated to SunEdison and TerraForm Global.

(3)Represents cash received from SunEdison in satisfaction of outstanding claims made under engineering, procurement and construction contracts as discussed above.

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Related Parties - Other Brookfield Transactions and Agreements (Details) - USD ($) $ / shares in Units, $ in Thousands					3 Months Ended		12 Months Ended
	Oct. 08, 2019	Aug. 03, 2018	Jun. 12, 2018	Jun. 11, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
New issuances of common stock (in shares)		80,084					2,982,000	61,056,000
Stock issued in period							$ 298,768	$ 650,881	$ 0
Issued of Common Stock in public offering (in shares)							14,907,000	0
Proceeds from issuance of Class A common stock, net of issuance costs							$ 298,767	$ 650,000	0
Net proceeds as a capital contribution							(3,028)	(3,123)	$ (3,772)
Acquisition-Related Costs Payable
Related Party Transaction [Line Items]
Amount due to affiliate							1,400
Payments to affiliate								4,000
Affiliated Entity | Credit Support
Related Party Transaction [Line Items]
Percentage of savings realized in transaction						50.00%
Payments to affiliate					$ 2,900	$ 2,900
Affiliate of Brookfield | Financial Swap of Commodity Contracts - Flow Through Reimbursement Received
Related Party Transaction [Line Items]
Receipts from (payments) to affiliates for commodity contracts							$ 500
Affiliate of Brookfield | Financial Swap of Commodity Contracts - Flow Through Costs Paid
Related Party Transaction [Line Items]
Receipts from (payments) to affiliates for commodity contracts								$ (1,200)
Share Purchase Agreement
Related Party Transaction [Line Items]
New issuances of common stock (in shares)				60,975,609
Price per share of common stock (usd per share)				$ 10.66
Stock issued in period				$ 650,000
Percentage of ownership after transaction				65.00%
Private Placement
Related Party Transaction [Line Items]
Issued of Common Stock in public offering (in shares)	2,981,514			60,975,609
Sale of stock, price per share (in usd per share)	$ 16.77			$ 10.66
Proceeds from issuance of Class A common stock, net of issuance costs	$ 50,000			$ 650,000
Affiliates of Brookfield | TerraForm Power | Share Purchase Agreement
Related Party Transaction [Line Items]
Percentage of ownership after transaction			65.00%					65.00%
Affiliates of Brookfield | TerraForm Power | Private Placement
Related Party Transaction [Line Items]
Percentage of ownership after transaction	62.00%
Brookfield and Affiliates | Affiliated Entity
Related Party Transaction [Line Items]
Income from related party								$ 3,700
Net proceeds as a capital contribution								$ 3,000
Common Class A | Chamblee Class Action
Related Party Transaction [Line Items]
New issuances of common stock (in shares)		80,084

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Nature of Operations and Organization

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Organization

NATURE OF OPERATIONS AND ORGANIZATION

Nature of Operations

TerraForm Power, Inc. (“TerraForm Power” and, together with its subsidiaries, the “Company”) is a holding company and its primary asset is an equity interest in TerraForm Power, LLC (“Terra LLC”). TerraForm Power is the managing member of Terra LLC and operates, controls and consolidates the business affairs of Terra LLC, which through its subsidiaries owns and operates renewable energy facilities that have long-term contractual arrangements to sell the electricity generated by these facilities to third parties. The related green energy certificates, ancillary services and other environmental attributes generated by these facilities are also sold to third parties. The Company is sponsored by Brookfield Asset Management Inc. (“Brookfield”) and its primary business strategy is to acquire operating solar and wind assets in North America and Western Europe. The Company is a controlled affiliate of Brookfield. As of December 31, 2019, affiliates of Brookfield held approximately 62% of the Company’s Common Stock.

Brookfield Renewable Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal (the “Brookfield Proposal”) from Brookfield Renewable Partners L.P. (“Brookfield Renewable”), an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board of Directors of the Company (the “Board”) consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a special committee (the “Special Committee”) of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into a definitive agreement (the “Reorganization Agreement”) for Brookfield Renewable to acquire all of the Company’s outstanding shares of Common Stock, other than the approximately 62% currently owned by Brookfield Renewable and its affiliates (the transactions contemplated by the Reorganization Agreement, the “Transactions”). Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

The Consummation of the Brookfield Sponsorship Transaction and the Settlement with SunEdison

Prior to the consummation of the Merger (as defined below) on October 16, 2017, TerraForm Power was a controlled affiliate of SunEdison (together with its consolidated subsidiaries and excluding the Company and TerraForm Global, Inc. (“TerraForm Global”) and their subsidiaries, “SunEdison”). Upon the consummation of the Merger, a change of control of TerraForm Power occurred, and Orion US Holdings 1 L.P. (“Orion Holdings”), an affiliate of Brookfield, held 51% of the voting securities of TerraForm Power. As a result of the Merger, TerraForm Power is no longer a controlled affiliate of SunEdison and became a controlled affiliate of Brookfield. In June 2018, TerraForm Power closed a private placement to certain affiliates of Brookfield such that, as of December 31, 2018, affiliates of Brookfield held approximately 65% of TerraForm Power’s Common Stock. On October 8, 2019, the Company completed a public offering and a simultaneous private placement to certain affiliates of Brookfield of its Common Stock whereby as of December 31, 2019, the combined ownership of affiliates of Brookfield was approximately 62%.

On April 21, 2016, SunEdison and certain of its domestic and international subsidiaries (the “SunEdison Debtors”) voluntarily filed for protection under Chapter 11 of the U.S. Bankruptcy Code (the “SunEdison Bankruptcy”). In response to SunEdison’s financial and operating difficulties, the Company initiated a process for the exploration and evaluation of potential

strategic alternatives for the Company, including potential transactions to secure a new sponsor or sell the Company, and a process to settle claims with SunEdison. This process resulted in the Company’s entry into a definitive Merger and Sponsorship Transaction agreement on March 6, 2017 with Orion Holdings and BRE TERP Holdings Inc. (“Merger Sub”), a wholly-owned subsidiary of Orion Holdings, each of which is an affiliate of Brookfield. At the same time, the Company and SunEdison also entered into a settlement agreement (the “Settlement Agreement”) and a voting and support agreement (the “Voting and Support Agreement”), to among other things, facilitate the closing of the Merger and the settlement of claims between the Company and SunEdison.

On October 6, 2017, the Merger Agreement was approved by the holders of a majority of the outstanding Class A shares of TerraForm Power, excluding SunEdison, Orion Holdings, any of their respective affiliates or any person with whom any of them has formed (and not terminated) a “group” (as such term is defined in the Securities Exchange Act of 1934 as amended, the “Exchange Act”) and by the holders of a majority of the total voting power of the outstanding shares of the Company’s common stock entitled to vote on the transaction. With these votes, all conditions to the merger transaction contemplated by the Merger Agreement were satisfied. On October 16, 2017, Merger Sub merged with and into TerraForm Power (the “Merger”), with TerraForm Power continuing as the surviving corporation in the Merger. Immediately following the consummation of the Merger, there were 148,086,027 Class A shares of TerraForm Power outstanding (which excludes 138,402 Class A shares that were issued and held in treasury to pay applicable employee tax withholdings for restricted stock units (“RSUs”) held by employees that vested upon the consummation of the Merger) and Orion Holdings held 51% of such shares. In addition, pursuant to the Merger Agreement, at or prior to the effective time of the Merger, the Company and Orion Holdings (or one of its affiliates), among other parties, entered into a suite of agreements providing for sponsorship arrangements, including a master services agreement, relationship agreement, governance agreement and a sponsor line of credit (the “Sponsorship Transaction”), as are more fully described in Note 10. Long-term Debt and Note 21. Related Parties.

Immediately prior to the effective time of the Merger, pursuant to the Settlement Agreement, SunEdison exchanged all of the Class B units held by SunEdison or any of its controlled affiliates in Terra LLC for 48,202,310 Class A shares of TerraForm Power, and as a result of this exchange, all shares of Class B common stock of TerraForm Power held by SunEdison or any of its controlled affiliates were automatically redeemed and retired. Pursuant to the Settlement Agreement, immediately following this exchange, the Company issued to SunEdison additional Class A shares such that immediately prior to the effective time of the Merger, SunEdison and certain of its affiliates held an aggregate number of Class A shares equal to 36.9% of the Company’s fully diluted share count (which was subject to proration based on the Merger consideration election results as discussed in Note 16. Stockholders’ Equity). SunEdison and certain of its affiliates also transferred all of the outstanding IDRs of Terra LLC held by SunEdison or certain of its affiliates to Brookfield IDR Holder at the effective time of the Merger. Under the Settlement Agreement, upon the consummation of the Merger, all agreements between the Company and the SunEdison Debtors were deemed rejected, subject to certain limited exceptions, without further liability, claims or damages on the part of the Company. The settlements, mutual release and certain other terms and conditions of the Settlement Agreement also became effective upon the consummation of the Merger, as more fully discussed in Note 21. Related Parties.

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Cover - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 28, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-36542
Entity Registrant Name	TerraForm Power, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-4780940
Entity Address, Address Line One	200 Liberty Street,
Entity Address, Address Line Two	14th Floor
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10281
City Area Code	646
Local Phone Number	992-2400
Title of 12(b) Security	Common Stock, Class A, par value $0.01
Trading Symbol	TERP
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 1.1
Entity Common Stock, Shares Outstanding		226,521,289
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to its 2020 annual meeting of stockholders (the “2020 Proxy Statement”) are incorporated by reference into Part III of this Form 10-K where indicated. The 2020 Proxy Statement will be filed with the U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.
Entity Central Index Key	0001599947
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false

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Concentration Of Credit Risk

12 Months Ended

Dec. 31, 2019

Risks and Uncertainties [Abstract]

Concentration of Credit Risk

CONCENTRATION OF CREDIT RISK

The Company’s financial assets are typically subject to concentrations of credit risk and primarily consist of cash and cash equivalents, accounts receivable and derivative assets. The following table reflects the balances of the major financial assets that are subject to concentrations of credit risk as of December 31, 2019, and 2018:

	As of December 31,
(In thousands)	2019		2018
Cash and cash equivalents	$	349,500	$	392,809
Accounts receivable, net	167,865		145,161
Derivative assets	73,536		105,355
Total	$	590,901	$	643,325

Cash and Cash Equivalents

The Company is subject to concentrations of credit risk related to the cash and cash equivalents that may exceed the insurable limits in the related jurisdictions. The maximum exposure to loss due to credit risk would generally equal the stated value of cash and cash equivalents in the above table. The Company places its cash and cash equivalents with creditworthy financial institutions and, historically, did not experience any losses with regards to balances in excess of insured limits or as a result of other concentrations of credit risk.

Accounts Receivable, Net

The Company serves hundreds of customers in three continents, and, in the United States, the Company’s customers are spread across various states resulting in the diversification of its customer base. Notwithstanding this diversification, a significant portion of the Company’s offtake counterparties are government-backed entities and public utility companies, which has the potential to impact the Company’s exposure to credit risk.

Major Customers

The following table reflects operating revenues, net for the years ended December 31, 2019, 2018 and 2017, by specific customers exceeding 10% of total net operating revenues:

		Year Ended December 31,
		2019				2018				2017
(In thousands, except for percentages)	Segment	Amount		Percentage		Amount		Percentage		Amount		Percentage
Comisión Nacional de los Mercados y la Competencia1	Regulated Solar and Wind	$	240,714	25.6	%	$	127,912	16.7	%	N/A		N/A
Tennessee Valley Authority2	Wind	93,920		10.0		90,283		11.8		$	79,773	13.1	%
San Diego Gas & Electric3	Solar	N/A		N/A		N/A		N/A		63,905		10.5

———

(1)The Company earned $338.7 million and $186.7 million from the Spanish Electricity System for the years ended December 31, 2019, and 2018, respectively, of which $240.7 million and $127.9 million were through collections from the Comisión Nacional de los Mercados y la Competencia (“CNMC”). These operating revenues were earned within the Regulated Solar and Wind segment and represented 25.6% and 16.7% of the Company’s net consolidated operating revenues for these years, respectively. The CNMC is the state-owned regulator of the Spanish Electricity System who collects the funds payable, mainly from the tariffs to end user customers, and is responsible for the calculation and the settlement of regulated payments.

(2)The Company earned $93.9 million and $90.3 million operating revenues from the Tennessee Valley Authority (“TVA”) for the years ended December 31, 2019, and 2018, respectively. These operating revenues were earned within the Regulated Solar and Wind segment and represented 10.0% and 11.8% of the Company’s net consolidated operating revenues for these years, respectively. The TVA is a corporation wholly-owned by the U.S. government that sells power mainly to wholesale customers in several states in the Southern part on the U.S.

(3)This customer did not exceed 10% of total operating revenue for the year ended December 31, 2019.

The amounts receivable from the CNMC and TVA as of December 31, 2019, and 2018, were as follows:

	As of December 31,
(In thousands)	2019		2018
CNMC	$	78,474	$	64,739
TVA	12,722		9,715
Total	$	91,196	$	74,454

If the CNMC or the TVA were to cease to honor their obligations to the Company it would have a material adverse effect on the Company’s business, operating results or financial position. The Company’s management believes that the concentration of risk with the CNMC is mitigated by, among other things, the indirect support of the Spanish government for the CNMC’s obligations and, in general, by the regulated rate system in Spain. Similarly, the Company’s management believes that the concentration risk of the credit risk with the TVA is mitigated by, among other things, the indirect support of the U.S. government.

Derivative Assets

The Company is subject to credit risk related to its derivatives to the extent the hedge counterparties may be unable to meet the terms of the contractual arrangements. The maximum exposure to loss due to credit risk if counterparties fail completely to perform according to the terms of the contracts would generally equal the fair value of derivative assets presented in the above table. The Company seeks to mitigate credit risk by transacting with a group of creditworthy financial institutions and through the use of master netting arrangements.

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Schedule of Preliminary Allocation of the Acquisition-date Fair Values of Assets Acquired and Liabilities Assumed

The preliminary allocation of the acquisition-date fair values of assets, liabilities and non-controlling interests pertaining to this business combination as of December 31, 2019, were as follows:

(In thousands)	As of September 26, 2019
Renewable energy facilities in service1	$	581,717
Intangible assets	168,825
Accounts receivable	13,160
Prepaid expenses and other assets	9,734
Total assets acquired	773,436
Accounts payable, accrued expenses and other current liabilities	6,806
Asset retirement obligations	27,338
Operating lease liabilities	21,663
Other liabilities	7,650
Total liabilities assumed	63,457
Non-controlling interests2	3,028
Purchase price, net of cash and restricted cash acquired3	706,951
Deposit on acquisitions	24,831
Total cash paid for the WGL Acquisition, net of cash acquired3	$	731,782

———

(1)Includes $22.6 million operating lease right-of-use assets.

(2)The fair value of the non-controlling interests was determined using an income approach representing the best indicator of fair value and was supported by a discounted cash flow technique.

(3)The Company acquired cash and cash equivalents of $3.4 million as of the acquisition date.

The final allocation of the acquisition-date fair values of assets, liabilities and redeemable non-controlling interests pertaining to this business combination as of December 31, 2019, was as follows:

(In thousands)	As of June 12, 2018, reported at December 31, 2018		Adjustments		As of June 12, 2019, reported at December 31, 2019
Renewable energy facilities in service	$	1,993,520	$	252,071	$	2,245,591
Accounts receivable	91,343		—		91,343
Intangible assets	1,034,176		(290,171)		744,005
Goodwill1	123,106		10,195		133,301
Other assets	43,402		2,845		46,247
Total assets acquired	3,285,547		(25,060)		3,260,487
Accounts payable, accrued expenses and other current liabilities	93,032		(1,761)		91,271
Long-term debt, including current portion	1,906,831		(12,405)		1,894,426
Deferred income taxes	171,373		(10,800)		160,573
Asset retirement obligations	67,706		(94)		67,612
Derivative liabilities	137,002		—		137,002
Other long-term liabilities	23,002		—		23,002
Total liabilities assumed	2,398,946		(25,060)		2,373,886
Redeemable non-controlling interests2	55,117		—		55,117
Purchase price, net of cash acquired3	$	831,484	$	—	$	831,484

———

(1)The excess purchase price over the estimated fair value of net assets acquired of $133.3 million was recorded as goodwill, with $103.8 million assigned to the Regulated Solar and Wind segment and $29.5 million assigned to the Wind segment. See Note 7. Intangible Assets, Net and Goodwill and Note 23. Segment Reporting for additional details.

(2) The fair value of the non-controlling interests was determined using a market approach using a quoted price for the instrument. As discussed above, the Company acquired the remaining shares of Saeta pursuant to a statutory squeeze out procedure under Spanish law, which closed on July 2, 2018. The quoted price for the purchase of the non-controlling interest was the best indicator of fair value and was supported by a discounted cash flow technique.

(3)The Company acquired cash and cash equivalents of $187.2 million and restricted cash of $95.1 million as of the acquisition date.

Summary of Estimated Fair Values and Weighted Average Amortization Periods of Acquired Intangible Assets

The Company attributed the intangible asset values to favorable rate revenue contracts and PPAs in-place from renewable energy facilities and the intangible liabilities to unfavorable rate revenue contracts. The following table summarizes the estimated fair values and the weighted average amortization periods of the acquired intangible assets and assumed intangible liabilities as of the acquisition date:

	WGL Acquisition
	Fair Value (In thousands)		Weighted Average Amortization Period
Favorable rate revenue contracts	$	27,400	16 years
In-place value of market rate revenue contracts	141,425		15 years
Unfavorable rate revenue contracts	7,650		2 years

———

(1)For the purposes of this disclosure, the weighted average amortization periods are determined based on a weighting of the individual intangible fair values against the total fair value for each major intangible asset class.

The following table summarizes the estimated fair value and weighted average amortization period of acquired intangible assets as of the acquisition date for Saeta:

	Saeta as of June 12, 2018
	Fair Value (In thousands)		Weighted Average Amortization Period (In years)1
Intangible assets - licensing contracts	$	744,005	14 years

———

(1)For purposes of this disclosure, the weighted average amortization period is determined based on a weighting of the individual intangible fair values against the total fair value for each major intangible asset and liability class.

Unaudited Pro Forma Supplementary Data

The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed to be indicative of the Company’s results of operations had the acquisition been consummated on the date assumed or of the Company’s consolidated results of operations for any future date.

	Year Ended December 31,
(In thousands)	2019		2018
Total operating revenues, net	$	1,011,526	$	831,145
Net loss	(214,280)		(185,392)

The unaudited pro forma supplementary data presented in the table below shows the effect of the Saeta acquisition, as if the transaction had occurred on January 1, 2017. The pro forma net loss includes interest expense related to incremental borrowings used to finance the transaction and adjustments to depreciation and amortization expense for the valuation of renewable energy facilities and intangible assets. The pro forma net loss for the year ended December 31, 2019, excludes the impact of acquisition related costs disclosed below. The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed to be indicative of the Company’s results of operations had the acquisition been consummated on the date assumed or of the Company’s results of operations for any future date.

(In thousands)	Year Ended December 31, 2018
Total operating revenues, net	$	950,992
Net loss	(143,903)

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Consolidated Balance Sheets - (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Renewable energy facilities, net		$ 6,470,026
Renewable energy facilities in service, net	$ 7,405,461
Intangible assets, net	1,793,292	1,996,404
Current portion of long-term debt and financing lease obligations	441,951	464,332
Long-term debt and financing lease obligations, less current portion	5,793,431	5,297,513
Operating lease obligations, less current portion	272,894
Asset retirement obligations	$ 287,288	$ 212,657
Common stock par value (usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,200,000,000	1,200,000,000
Common stock, shares issued (in shares)	227,552,105	209,642,140
Treasury stock (in shares)	1,051,298	500,420
Consolidated variable interest entities
Renewable energy facilities, net	$ 3,188,508	$ 3,064,675
Renewable energy facilities in service, net	3,188,508
Intangible assets, net	690,594	751,377
Current portion of long-term debt and financing lease obligations	55,089	64,251
Long-term debt and financing lease obligations, less current portion	932,862	885,760
Operating lease obligations, less current portion	138,816
Asset retirement obligations	$ 116,159	$ 86,457

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The income tax expense (benefit) was calculated based on the income and losses before income tax between U.S. and foreign operations as follows:

(In thousands)	2019		2018		2017
(Loss) income before income taxes:
United States	$	(212,995)	$	(182,289)	$	(292,190)
Foreign	18,308		16,672		36,246
Loss before income taxes	$	(194,687)	$	(165,617)	$	(255,944)

The income tax provision consisted of the following:

(In thousands)	Current		Deferred		Total
Year ended December 31, 2019
U.S. federal	$	145	$	4,728	$	4,873
State and local	134		3,197		3,331
Foreign	4,636		(942)		3,694
Total expense	4,915		6,983		11,898
Tax benefit in equity	—		(978)		(978)
Total	$	4,915	$	6,005	$	10,920
Year ended December 31, 2018
U.S. federal	$	(461)	$	(18,301)	$	(18,762)
State and local	323		(4,376)		(4,053)
Foreign	2,739		7,786		10,525
Total expense (benefit)	2,601		(14,891)		(12,290)
Tax expense in equity	—		2,826		2,826
Total	$	2,601	$	(12,065)	$	(9,464)
Year ended December 31, 2017
U.S. federal	$	(45)	$	(20,489)	(20,534)
State and local	95		(1,211)		(1,116)
Foreign	220		1,789		2,009
Total expense (benefit)	270		(19,911)		(19,641)
Tax expense in equity	—		14,081		14,081
Total	$	270	$	(5,830)	$	(5,560)

Effective Tax Rate

The income tax provision differed from the expected amounts computed by applying the statutory U.S. federal income tax rate of 21% as of December 31, 2019 and December 31, 2018 and 35% as of December 31, 2017, to loss before income taxes, as follows:

	Year Ended December 31,
	2019		2018		2017
Income tax benefit at U.S. federal statutory rate	21.0	%	21.0	%	35.0	%
Increase (reduction) in income taxes:
State income taxes, net of U.S. federal benefit	5.9		5.0		4.0
Foreign operations	(2.0)		(0.5)		8.7
Non-controlling interests	(8.0)		(25.9)		(9.4)
Permanent differences	(0.2)		(1.6)		—
Tax Act rate change impact	—		—		2.0
Return to provision	—		—		2.8
Change in valuation allowance	(22.4)		7.8		(34.1)
Other	(0.4)		1.6		—
Effective tax rate	(6.1)	%	7.4	%	9.0	%

Prior to the consummation of the Merger on October 16, 2017, TerraForm Power owned approximately 66% of Terra LLC and SunEdison owned approximately 34% of Terra LLC. On October 16, 2017, pursuant to the Settlement Agreement, SunEdison transferred its interest in Terra LLC to TerraForm Power. Since the date of this transaction, TerraForm Power owns 100% of the capital and profits interest in Terra LLC, except for the IDRs which are owned by Brookfield IDR Holder. The Merger resulted in a change in control to occur subjecting TerraForm Power’s loss carryforwards to be limited for future usage under Internal Revenue Code Section 382.

On December 31, 2018, the Company executed a reorganization of its Capital Dynamics portfolio which resulted in no current tax impact by effectively moving the stock of the Capital Dynamics corporate entities up to TerraForm Power and then immediately contributing Capital Dynamics project assets to Terra LLC. The Company recognized a deferred tax benefit of $20.1 million during the year ended December 31, 2018, resulting from an excess net deferred tax liability that was previously recognized by TerraForm Power Holdings, Inc. as a separate taxpayer which is now expected to reverse in future periods as part of the U.S. federal and state tax consolidated group and provide a source of future taxable income to realize the Company’s net operating loss (“NOL”) carryforwards.

For the years ended December 31, 2019 and December 31, 2018, the overall effective tax rate was different than the statutory rate of 21% primarily due to the recording of a valuation allowance on certain income tax benefits attributed to the Company, losses allocated to non-controlling interests, the 2018 revaluation of deferred federal and state tax balances for TerraForm Power Holdings, Inc., and the effect of foreign and state taxes. For the year ended December 31, 2017, the overall effective tax rate was different from the statutory tax rate of 35% primarily due to the recording of a valuation allowance on certain income tax benefits attributed to the Company, losses allocated to non-controlling interests, the 2017 revaluation of deferred federal and state tax balances and the effect of foreign and state taxes.

The tax effects of the major items recorded as deferred tax assets and liabilities were as follows:

	As of December 31,
(In thousands)	2019		2018
Deferred tax assets:
Net operating losses and tax credit carryforwards	$	623,858	$	587,833
Derivative Liabilities	26,087		33,261
Interest expense limitation carryforward	117,598		67,887
Total deferred tax assets	767,543		688,981
Valuation allowance	(413,884)		(386,336)
Net deferred tax assets	353,659		302,645
Deferred tax liabilities:
Investment in partnership	270,237		221,694
Renewable energy facilities	107,908		30,261
Intangible assets	169,195		229,363
Other	858		176
Total deferred tax liabilities	548,198		481,494
Net deferred tax liabilities	$	194,539	$	178,849

For U.S. income tax purposes, Terra LLC is taxed as a U.S. partnership and controls the underlying renewable energy facilities. Thus, the tax effects of temporary differences related to the Company’s portfolio companies are captured within the net deferred tax liability for the investment in the partnership. At December 31, 2019, the Company has gross NOL carryforwards of $2.29 billion in the U.S. and gross NOL carryforwards of $132.1 million in foreign jurisdictions that will both expire in tax years beginning in 2035. Of the $2.3 billion of gross NOL carryforwards generated in the U.S., approximately $0.56 billion are limited and are expected to expire unused. For the remaining $1.73 billion, the Company does not believe it is more likely than not that it will generate sufficient taxable income to realize this entire amount. Consequently, the Company has recorded a valuation allowance against its deferred tax assets, net of the deferred tax liability related to the Company’s partnership investments that is expected to reverse within the NOL carryforward period with the exception of certain NOL at its Canadian, Portuguese, Spanish and Uruguayan operations. The current year movement in the valuation allowance is related to losses generated in the current year as a result of the current year operations and changes in the Company’s tax accounting methods and the limitations on such U.S. Federal and State losses as a result of U.S. Tax Reform.

Prior to the acquisition of Saeta, the Company’s foreign entities had cumulative negative earnings and profits, therefore, those entities had no earnings to repatriate back to the U.S. Following the enactment of the Tax Act and the current year acquisition of Saeta, the Company does not assert the indefinite reinvestment related to undistributed earnings of its foreign subsidiaries. The Company plans to utilize earnings generated by its foreign subsidiaries to make strategic acquisitions abroad and repatriate any excess earnings. The Company’s management determined there was no material deferred tax liabilities that needed to be recognized as of December 31, 2019.

The 2017 Tax Act included a provision to tax global intangible low tax income (“GILTI”) of foreign subsidiaries in excess of a standard rate of return. The Company will record expense related to GILTI in the period the tax is incurred. For the year ended December 31, 2019, the Company was in an overall tested loss position for GILTI purposes and therefore has not included GILTI in its calculation of taxable loss. The U.S. Treasury has issued additional guidance through notices and final regulations during 2019 which did not significantly impact the Company’s interpretation of the 2017 Tax Act. The Company will continue to monitor developments as they occur.

As of December 31, 2019 and 2018, the Company had not identified any uncertain tax positions for which a liability was required under ASC 740-10.

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Label	Element	Value
Non-Controlling Interests, Retained Earnings (Accumulated Deficit) [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (308,000)
Parent [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 20,414,000

[1] Represents the effect of the adoption of Accounting Standards Update (“ASU”) No. 2014-09, ASU No. 2016-08, ASU No. 2017-12 and ASU No. 2018-02 as of January 1, 2018.

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Intangible Assets, Net And Goodwill

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets, Net And Goodwill

INTANGIBLE ASSETS, NET AND GOODWILL

The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2019:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization		Net Book Value
Licensing agreements	13 years	$	765,451	$	(81,647)	$	683,804
Favorable rate revenue contracts	12 years	745,784		(195,287)		550,497
In-place value of market rate revenue contracts	16 years	688,832		(129,841)		558,991
Total intangible assets, net		$	2,200,067	$	(406,775)	$	1,793,292
Unfavorable rate revenue contracts	8 years	$	48,420	$	(32,556)	$	15,864
Total intangible liabilities, net1		$	48,420	$	(32,556)	$	15,864

———

(1)The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2018:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization		Net Book Value
Licensing contracts1	15 years	$	1,015,824	$	(36,374)	$	979,450
Favorable rate revenue contracts	14 years	738,488		(166,507)		571,981
In-place value of market rate revenue contracts	18 years	532,844		(100,543)		432,301
Favorable rate land leases2	16 years	15,800		(3,128)		12,672
Total intangible assets, net		$	2,302,956	$	(306,552)	$	1,996,404
Unfavorable rate revenue contracts	6 years	$	58,508	$	(41,605)	$	16,903
Unfavorable rate operations and maintenance contracts	1 year	5,000		(3,802)		1,198
Unfavorable rate land lease2	14 years	1,000		(218)		782
Total intangible assets, net3		$	64,508	$	(45,625)	$	18,883

———

(1)Represents the intangible assets recognized under the Saeta acquisition and attributed to licensing contracts in-place from the acquired solar and wind facilities. See Note 3. Acquisitions and Divestitures for additional details.

(2)On January 1, 2019, these amounts were reclassified to right-of-use assets in connection with the adoption of Topic 842. See Note 2. Summary of Significant Accounting Policies and Note 8. Leases for additional details.

(3)The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

Amortization expense related to the licensing contracts acquired from Saeta is reflected in the consolidated statements of operations within depreciation, accretion and amortization expense. During the years ended December 31, 2019 and 2018, amortization expense related to the licensing contracts was $66.9 million and $36.4 million, respectively.

Amortization expense related to favorable rate revenue contracts is reflected in the consolidated statements of operations as a reduction of operating revenues, net. Amortization related to unfavorable rate revenue contracts is reflected in the consolidated statements of operations as an increase to operating revenues, net. During the years ended December 31, 2019, 2018 and 2017, net amortization expense related to favorable and unfavorable rate revenue contracts resulted in a reduction of operating revenues, net of $39.9 million, $38.8 million and $39.6 million, respectively.

Amortization expense related to the in-place value of market rate revenue contracts is reflected in the consolidated statements of operations within depreciation, accretion and amortization expense. During the years ended December 31, 2019, 2018 and 2017, amortization expense related to the in-place value of market rate revenue contracts was $26.2 million, $28.2 million, and $25.5 million, respectively.

Over the next five years, the Company expects to recognize annual amortization on its intangibles as follows:

(In thousands)	2020		2021		2022		2023		2024
Favorable rate revenue contracts	$	47,555	$	44,789	$	43,598	$	43,598	$	43,598
Unfavorable rate revenue contracts	(7,545)		(2,710)		(1,628)		(1,007)		(279)
Total net amortization expense recorded to operating revenues, net	$	40,010	$	42,079	$	41,970	$	42,591	$	43,319
Licensing contracts	$	57,152	$	57,152	$	57,152	$	57,152	$	57,152
In-place value of market rate revenue contracts	38,517		38,517		38,517		38,510		38,503
Total amortization expense recorded to depreciation, accretion and amortization expense	$	95,669	$	95,669	$	95,669	$	95,662	$	95,655

GOODWILL

Goodwill represents the excess of the consideration transferred over the fair values of assets acquired and liabilities assumed from business combinations, and reflects the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. The goodwill balance is not deductible for income tax purposes.

The following table presents the activity of the goodwill balance for the years ended December 31, 2019, and 2018:

(In thousands)	Goodwill
Balance as of December 31, 2017	$	—
Goodwill resulting from business combination1	115,381
Adjustments during the period1	7,726
Foreign exchange differences	(2,554)
Balance as of December 31, 2018	120,553
Adjustments during the period2	10,196
Foreign exchange differences	(2,797)
Balance as of December 31, 2019	$	127,952

———

(1)Represents the excess purchase price over the estimated fair value of net assets acquired from Saeta and is primarily attributable to deferred tax liabilities and adjustment to the fair value of certain non-recourse project long-term debt. See Note 3. Acquisitions and Divestitures for additional details.

(2)Represents adjustments to the purchase price allocation of the assets acquired and liabilities assumed from the Saeta acquisition. See Note 3. Acquisitions and Divestitures for additional details.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisitions And Divestitures

ACQUISITIONS AND DIVESTITURES

2019 Acquisitions

(i) WGL Acquisition

On September 26, 2019, TerraForm Arcadia Holdings, LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Company (“TerraForm Arcadia”), completed the acquisition of an approximately 320 MW distributed generation portfolio of renewable energy facilities in the United States from subsidiaries of AltaGas Ltd., a Canadian corporation (“AltaGas”), for a purchase price of $720.0 million, plus $15.1 million for working capital. The acquisition was pursuant to a membership interest purchase agreement (the “Purchase Agreement”) dated July 19, 2019, entered into by TerraForm Arcadia, WGL Energy Systems, Inc., a Delaware corporation (“WGL”), and WGSW, Inc., a Delaware corporation (“WGSW”, and together with WGL, the “Sellers”), both subsidiaries of AltaGas (the “WGL Acquisition”). Pursuant to the Purchase Agreement, the ownership of certain projects for which the Sellers had not yet received the required third party consents or had not completed construction as of the closing date (the “Delayed Projects”) were to be transferred to the Company once such third party consents were received or construction was completed, subject to certain terms and conditions. The Delayed Projects represented 11.6 MW of the combined nameplate capacity of the acquired renewable energy facilities as

of December 31, 2019. The purchase price allocated to the Delayed Projects based on the Purchase Agreement was $24.8 million, and is presented as Deposit on acquisitions on the consolidated balance sheets. In the event that the title to certain Delayed Projects is not transferred to the Company within a certain period of time, the Company is entitled to a full refund of the value of these projects based on the Purchase Agreement.

The Company funded the purchase price and the related initial costs of the WGL Acquisition with the net proceeds of $475.0 million Bridge Facility and the remainder from draws on the Revolver. See Note 10. Long-term Debt for additional details.

The Company accounted for the WGL Acquisition under the acquisition method of accounting for business combinations. The final accounting has not been completed since the evaluation necessary to assess the fair values of acquired assets and assumed liabilities is still in process. The additional information needed by the Company to finalize the measurement of these provisional amounts include, but not limited to, additional information regarding certain energy markets in the United States, the estimation of the removal costs for the acquired assets, the completion of the transfer of the Delayed Projects, and the assessment of the incremental borrowing rate for operating leases. The provisional amounts for this business combination are subject to revision until these evaluations are completed.

The preliminary allocation of the acquisition-date fair values of assets, liabilities and non-controlling interests pertaining to this business combination as of December 31, 2019, were as follows:

(In thousands)	As of September 26, 2019
Renewable energy facilities in service1	$	581,717
Intangible assets	168,825
Accounts receivable	13,160
Prepaid expenses and other assets	9,734
Total assets acquired	773,436
Accounts payable, accrued expenses and other current liabilities	6,806
Asset retirement obligations	27,338
Operating lease liabilities	21,663
Other liabilities	7,650
Total liabilities assumed	63,457
Non-controlling interests2	3,028
Purchase price, net of cash and restricted cash acquired3	706,951
Deposit on acquisitions	24,831
Total cash paid for the WGL Acquisition, net of cash acquired3	$	731,782

———

(1)Includes $22.6 million operating lease right-of-use assets.

(2)The fair value of the non-controlling interests was determined using an income approach representing the best indicator of fair value and was supported by a discounted cash flow technique.

(3)The Company acquired cash and cash equivalents of $3.4 million as of the acquisition date.

The acquired non-financial assets primarily represent an estimate of the fair value of the acquired renewable energy facilities and intangible assets from PPAs using the cost and income approach. Key inputs used to estimate fair value included forecasted power pricing, operational data, asset useful lives and a discount rate factor reflecting current market conditions at the time of the acquisition. These significant inputs are not observable in the market and thus represent Level 3 measurements, as defined in Note 13. Fair Value of Financial Instruments. Refer below for additional disclosures related to the acquired finite-lived intangible assets.

The results of operations from the acquired entities are included in the Company’s consolidated results since the date of acquisition. The operating revenues and net income related to the WGL Acquisition reflected in the consolidated statements of operations for the year ended December 31, 2019, were $13.8 million and $0.1 million, respectively.

Intangibles at Acquisition Date

The Company attributed the intangible asset values to favorable rate revenue contracts and PPAs in-place from renewable energy facilities and the intangible liabilities to unfavorable rate revenue contracts. The following table summarizes the estimated fair values and the weighted average amortization periods of the acquired intangible assets and assumed intangible liabilities as of the acquisition date:

	WGL Acquisition
	Fair Value (In thousands)		Weighted Average Amortization Period
Favorable rate revenue contracts	$	27,400	16 years
In-place value of market rate revenue contracts	141,425		15 years
Unfavorable rate revenue contracts	7,650		2 years

———

(1)For the purposes of this disclosure, the weighted average amortization periods are determined based on a weighting of the individual intangible fair values against the total fair value for each major intangible asset class.

Unaudited Pro Forma Supplementary Data

The unaudited pro forma supplementary data presented in the table below gives effect to the WGL Acquisition, as if the transaction had occurred on January 1, 2018. The pro forma net loss includes interest expense related to incremental borrowings used to finance the transaction and adjustments to depreciation, accretion and amortization expense for the valuation of renewable energy facilities, intangible assets, and asset retirement obligations, and excludes the impact of acquisition costs disclosed below. The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed to be indicative of the Company’s results of operations had the acquisition been consummated on the date assumed or of the Company’s consolidated results of operations for any future date.

	Year Ended December 31,
(In thousands)	2019		2018
Total operating revenues, net	$	1,011,526	$	831,145
Net loss	(214,280)		(185,392)

(ii) X-Elio Acquisition

On December 18, 2019, Cuanto De Luz, S.L.U., a wholly-owned subsidiary of the Company, completed the acquisition of approximately 45 MW utility-scale solar photovoltaic power facilities in Spain, from subsidiaries of X-Elio Energy, S.L., a Spanish corporation (the “X-Elio Acquisition”), for a total purchase price of €63.8 million (equivalent to $71.1 million at the date of the acquisition). The Company funded the acquisition with a portion of the net proceeds of the utility-scale wind non-recourse borrowing refinancing and cash available on hand. See Note 10. Long-term Debt for additional details. These facilities are regulated under the Spanish framework for renewable power, with approximately 21 years of remaining regulatory life. This transaction was accounted for as an acquisition of assets, whereby the Company acquired approximately $186.5 million renewable energy facilities, and $54.8 million intangible assets attributable to licensing contracts in-place from the acquired solar facilities using the cost and income approach.

(iii) Acquisition of 15.1 MW Distributed Generation Assets

During the year ended December 31, 2019, the Company acquired four distributed generation facilities located in the U.S. with a combined nameplate capacity of 15.1 MW from third parties for a total purchase price of $24.0 million plus working capital adjustments. The facilities are contracted under long-term PPAs with municipal offtakers. This transaction was accounted for as an acquisition of assets.

2018 Acquisitions

(i) Saeta Acquisition

On February 7, 2018, the Company announced that it intended to launch a voluntary tender offer (the “Tender Offer”) to acquire 100% of the outstanding shares of Saeta, a Spanish renewable power company with then over 1,000 MW of solar and wind facilities (approximately 250 MW of solar and 778 MW of wind) located primarily in Spain. The Tender Offer was for €12.20 in cash per share of Saeta. On June 8, 2018, the Company announced that Spain’s National Securities Market

Commission confirmed an over 95% acceptance of shares of Saeta in the Tender Offer (the “Tendered Shares”). On June 12, 2018, the Company completed the acquisition of the Tendered Shares for total aggregate consideration of $1.12 billion and the assumption of $1.91 billion of project-level debt. Having acquired 95.28% of the shares of Saeta, the Company then pursued a statutory squeeze out procedure under Spanish law to procure the remaining approximately 4.72% of the shares of Saeta for $54.6 million.

The Company funded the $1.12 billion purchase price of the Tendered Shares with $650.0 million of proceeds from the private placement of its Common Stock to Orion Holdings and BBHC Orion Holdco L.P. as discussed in Note 16. Stockholders’ Equity, along with approximately $471 million from its existing liquidity, including (i) the proceeds of a $30.0 million draw on its Sponsor Line (as defined in Note 10. Long-term Debt), (ii) a $359.0 million as part of a draw on the Company’s Revolver (as defined in Note 10. Long-term Debt), and (iii) approximately $82 million of cash on hand. The Company funded the purchase of the remaining approximately 4.72% non-controlling interest in Saeta using $54.6 million of the total proceeds from an additional draw on its Sponsor Line.

The Company accounted for the acquisition of Saeta under the acquisition method of accounting for business combinations. The purchase accounting for the Saeta acquisition, including assignment of goodwill to reporting units, was finalized as of June 30, 2019. The final allocation of the acquisition-date fair values of assets, liabilities and redeemable non-controlling interests pertaining to this business combination as of December 31, 2019, was as follows:

(In thousands)	As of June 12, 2018, reported at December 31, 2018		Adjustments		As of June 12, 2019, reported at December 31, 2019
Renewable energy facilities in service	$	1,993,520	$	252,071	$	2,245,591
Accounts receivable	91,343		—		91,343
Intangible assets	1,034,176		(290,171)		744,005
Goodwill1	123,106		10,195		133,301
Other assets	43,402		2,845		46,247
Total assets acquired	3,285,547		(25,060)		3,260,487
Accounts payable, accrued expenses and other current liabilities	93,032		(1,761)		91,271
Long-term debt, including current portion	1,906,831		(12,405)		1,894,426
Deferred income taxes	171,373		(10,800)		160,573
Asset retirement obligations	67,706		(94)		67,612
Derivative liabilities	137,002		—		137,002
Other long-term liabilities	23,002		—		23,002
Total liabilities assumed	2,398,946		(25,060)		2,373,886
Redeemable non-controlling interests2	55,117		—		55,117
Purchase price, net of cash acquired3	$	831,484	$	—	$	831,484

———

(1)The excess purchase price over the estimated fair value of net assets acquired of $133.3 million was recorded as goodwill, with $103.8 million assigned to the Regulated Solar and Wind segment and $29.5 million assigned to the Wind segment. See Note 7. Intangible Assets, Net and Goodwill and Note 23. Segment Reporting for additional details.

(2) The fair value of the non-controlling interests was determined using a market approach using a quoted price for the instrument. As discussed above, the Company acquired the remaining shares of Saeta pursuant to a statutory squeeze out procedure under Spanish law, which closed on July 2, 2018. The quoted price for the purchase of the non-controlling interest was the best indicator of fair value and was supported by a discounted cash flow technique.

(3)The Company acquired cash and cash equivalents of $187.2 million and restricted cash of $95.1 million as of the acquisition date.

The acquired non-financial assets primarily represent estimates of the fair value of acquired renewable energy facilities and intangible assets from licensing agreements using the cost and income approach. Key inputs used to estimate fair value included forecasted power pricing, operational data, asset useful lives, and a discount rate factor reflecting current market conditions at the time of the acquisition. These significant inputs are not observable in the market and thus represent Level 3 measurements (as defined in Note 13. Fair Value of Financial Instruments). Refer below for additional disclosures related to the acquired finite-lived intangible assets.

The results of operations of Saeta are included in the Company’s consolidated results since the date of acquisition for the year ended December 31, 2018, and for the entire year ended December 31, 2019. The operating revenues and net income

of Saeta reflected in the consolidated statements of operations for the year ended December 31, 2019 were $407.1 million and $57.6 million, respectively, and $221.2 million and $38.2 million for the year ended December 31, 2018, respectively.

Intangibles at Acquisition Date

The Company attributed intangible asset value to licensing contracts in-place from solar and wind facilities. These intangible assets are amortized on a straight-line basis over the estimated remaining useful life of the facility from the Company’s acquisition date. The following table summarizes the estimated fair value and weighted average amortization period of acquired intangible assets as of the acquisition date for Saeta:

	Saeta as of June 12, 2018
	Fair Value (In thousands)		Weighted Average Amortization Period (In years)1
Intangible assets - licensing contracts	$	744,005	14 years

———

(1)For purposes of this disclosure, the weighted average amortization period is determined based on a weighting of the individual intangible fair values against the total fair value for each major intangible asset and liability class.

Out-of-Period Adjustments

During the preparation of the Company’s consolidated financial statements for the year ended December 31, 2019, management discovered errors related to the Saeta business combination as included in the Company’s consolidated condensed financial statements for the year ended December 31, 2018, included in the previously filed Annual Report on Form 10-K for the related period, and the unaudited consolidated condensed financial statements for the periods ended March 31, 2019, June 30, 2019, and September 30, 2019, as included in the previously filed Quarterly Reports on Form 10-Q for the related periods. Specifically, the Company allocated the entire value of $258.3 million of acquired projects within the International Wind operating segment as intangible assets without an allocation to renewable energy facilities. Additionally, the Company overstated the estimated fair value of assumed non-recourse long-term project debt as of June 30, 2019, and September 30, 2019, by approximately $28.5 million. The correction of these errors resulted in a $258.3 million increase in renewable energy facilities, net, a $258.3 million decrease in intangible assets, a $28.5 million decrease in long-term debt, a $22.0 million decrease in goodwill, and a $6.5 million increase in deferred tax liabilities. The correction did not have a material impact on the previously reported amounts of net loss, and comprehensive loss, and did not have any impact on the previously reported consolidated cash flows from operating, investing, or financing activities.

The Company evaluated the errors and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company’s consolidated financial statements for any prior period. Therefore, amendments to the previously filed reports were not required.

Unaudited Pro Forma Supplementary Data

The unaudited pro forma supplementary data presented in the table below shows the effect of the Saeta acquisition, as if the transaction had occurred on January 1, 2017. The pro forma net loss includes interest expense related to incremental borrowings used to finance the transaction and adjustments to depreciation and amortization expense for the valuation of renewable energy facilities and intangible assets. The pro forma net loss for the year ended December 31, 2019, excludes the impact of acquisition related costs disclosed below. The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed to be indicative of the Company’s results of operations had the acquisition been consummated on the date assumed or of the Company’s results of operations for any future date.

(In thousands)	Year Ended December 31, 2018
Total operating revenues, net	$	950,992
Net loss	(143,903)

(ii) Acquisition of 6.1 MW Distributed Generation Portfolio

In 2018, the Company acquired six distributed generation facilities located in the U.S. with a combined nameplate capacity of 6.1 MW from third parties for a purchase price of $4.1 million, net of cash acquired. The facilities are contracted under long-term PPAs with municipal offtakers. This transaction was accounted for as an acquisition of assets.

Acquisition Costs

Total Acquisition costs incurred by the Company for the year ended December 31, 2019, were $4.7 million. Costs related to affiliates included in these balances were $0.9 million. Acquisition costs incurred by the Company for the year ended December 31, 2018 were $14.6 million. Costs related to affiliates included in these balances were $6.9 million. These costs are reflected as acquisition costs and acquisition costs - affiliate (see Note 21. Related Parties) in the consolidated statements of operations and are excluded from the unaudited pro forma net loss amount disclosed above.

2019 Divestiture

(i) Sale of Six Distributed Generation Facilities in the United States

On December 20, 2019, the Company sold six distributed generation facilities in the United States, with a combined nameplate capacity of 6.0 MW, for a net consideration of $9.5 million. The Company recognized a net gain of $2.3 million representing the difference between the net proceeds from the sale and the net carrying amount of assets sold and liabilities extinguished, was recorded in the consolidated statement of operations for the year ended December 31, 2019 within the gain on sale of renewable energy facilities.

2017 Divestitures

(i) U.K. Portfolio Sale

On May 11, 2017, the Company announced that it completed its sale of substantially all of its portfolio of solar power plants located in the United Kingdom (24 operating projects representing an aggregate 365.0 MW, the “U.K. Portfolio”) to Vortex Solar UK Limited, a renewable energy platform managed by the private equity arm of EFG Hermes, an investment bank. The Company received approximately $214.1 million of proceeds from the sale, which was net of transaction expenses of $3.9 million and distributions taken from the U.K. Portfolio after announcement and before closing of the sale. The Company also disposed of $14.8 million of cash and cash equivalents and $21.8 million of restricted cash as a result of the sale. The proceeds were used for the reduction of the Company’s indebtedness (a $30.0 million prepayment for a non-recourse portfolio term loan and the remainder was applied towards revolving loans outstanding under its senior secured corporate-level revolving credit facility). The sale also resulted in a reduction in the Company’s non-recourse project debt by approximately £301 million British pounds sterling at the U.K. Portfolio level. The Company recognized a gain on the sale of $37.1 million, which is reflected within Gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017. The Company retained one 11.1 MW solar project in the United Kingdom.

(ii) Residential Portfolio Sale

In 2017, the Company closed on the sale of 100% of the membership interests of Enfinity Colorado DHA 1, LLC, a Colorado limited liability company that owned and operated 2.5 MW of solar installations situated on the roof of public housing units located in Colorado and owned by the Denver Housing Authority, and 100% of the membership interests of TerraForm Resi Solar Manager, LLC, a subsidiary of the Company that owned and operated 8.9 MW of rooftop solar installations, to Greenbacker Residential Solar II, LLC. The Company received proceeds of $7.1 million during 2017 as a result of the sale of these companies and also disposed of $0.6 million of cash and cash equivalents and $0.8 million of restricted cash. There was no additional loss recognized during 2017 as a result of these sales.

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Intangible Assets, Net And Goodwill - Future Amortization Expense (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Favorable rate revenue contracts
Finite-Lived Intangible Assets [Line Items]
2020	$ 47,555
2021	44,789
2022	43,598
2023	43,598
2024	43,598
Unfavorable rate revenue contracts
Finite-Lived Intangible Assets [Line Items]
2020	7,545
2021	2,710
2022	1,628
2023	1,007
2024	279
Total net amortization expense recorded to operating revenues, net
Finite-Lived Intangible Assets [Line Items]
2020	40,010
2021	42,079
2022	41,970
2023	42,591
2024	43,319
Licensing agreements
Finite-Lived Intangible Assets [Line Items]
2020	57,152
2021	57,152
2022	57,152
2023	57,152
2024	57,152
In-place value of market rate revenue contracts
Finite-Lived Intangible Assets [Line Items]
2020	38,517
2021	38,517
2022	38,517
2023	38,510
2024	38,503
Total amortization expense recorded to depreciation, accretion and amortization expense
Finite-Lived Intangible Assets [Line Items]
2020	95,669
2021	95,669
2022	95,669
2023	95,662
2024	$ 95,655

XML

Long-Term Debt - Term Loan (Details) - USD ($)					3 Months Ended	12 Months Ended
	Oct. 05, 2018	May 11, 2018	Dec. 12, 2017	Nov. 08, 2017	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 08, 2019	Mar. 08, 2019	Feb. 06, 2018	Oct. 17, 2017
Debt Instrument [Line Items]
Loss on modification and extinguishment of debt, net					$ 31,100,000	$ 26,953,000	$ 1,480,000	$ 81,099,000
Interest rate swaps
Debt Instrument [Line Items]
Averaged fixed rate										2.54%
Term Loan
Debt Instrument [Line Items]
Loss on modification and extinguishment of debt, net						4,006,000	1,480,000	$ 0
Secured Debt | Term Loan
Debt Instrument [Line Items]
Term of instrument				5 years
Aggregate principal amount				$ 350,000,000.0
Interest rate decrease		0.75%
Loss on modification and extinguishment of debt, net						$ 4,000,000.0	$ 1,500,000
Secured Debt | Term Loan | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate				1.75%
Secured Debt | Term Loan | Eurodollar
Debt Instrument [Line Items]
Basis spread on variable rate				2.75%
Prepayment premium				1.00%
Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Aggregate principal amount									$ 800,000,000.00
Line of Credit | Revolver
Debt Instrument [Line Items]
Repayments of debt				$ 50,000,000.0
Line of Credit | Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Aggregate principal amount											$ 600,000,000.0	$ 450,000,000.0
Repayments of debt			$ 150,000,000.0
Interest rate decrease	0.75%

XML

Revenue - Operating Revenues, Net and Disaggregated by Revenue Source (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Operating revenues, net	$ 206,734	$ 253,808	$ 255,366	$ 225,332	$ 213,093	$ 246,042	$ 179,888	$ 127,547	$ 941,240	$ 766,570	$ 610,471
Amortization of favorable and unfavorable rate revenue contracts, net									(39,940)	(38,767)
Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									316,433	298,966
Amortization of favorable and unfavorable rate revenue contracts, net									(8,850)	(9,743)
Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									286,139	280,949
Amortization of favorable and unfavorable rate revenue contracts, net									(31,090)	(29,024)
Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									338,668	186,655
Amortization of favorable and unfavorable rate revenue contracts, net									0	0
PPA rental income
Disaggregation of Revenue [Line Items]
Operating revenues, net									390,774	390,934
PPA rental income | Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									199,266	198,610
PPA rental income | Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									191,508	192,324
PPA rental income | Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									0	0
Commodity derivatives
Disaggregation of Revenue [Line Items]
Operating revenues, net									37,054	46,287
Commodity derivatives | Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									0	0
Commodity derivatives | Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									37,054	46,287
Commodity derivatives | Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									0	0
PPA and market energy revenue
Disaggregation of Revenue [Line Items]
Operating revenues, net									223,946	153,306
PPA and market energy revenue | Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									46,740	39,566
PPA and market energy revenue | Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									79,253	54,998
PPA and market energy revenue | Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									97,953	58,742
Capacity revenue from remuneration programs
Disaggregation of Revenue [Line Items]
Operating revenues, net									204,991	108,242
Capacity revenue from remuneration programs | Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									0	0
Capacity revenue from remuneration programs | Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									0	0
Capacity revenue from remuneration programs | Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									204,991	108,242
Energy revenue
Disaggregation of Revenue [Line Items]
Operating revenues, net									816,825	660,002
Energy revenue | Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									237,156	228,433
Energy revenue | Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									276,725	264,585
Energy revenue | Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									302,944	166,984
Incentive revenue
Disaggregation of Revenue [Line Items]
Operating revenues, net									124,415	106,568
Incentive revenue | Solar
Disaggregation of Revenue [Line Items]
Operating revenues, net									79,277	70,533
Incentive revenue | Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									9,414	16,364
Incentive revenue | Regulated Solar and Wind
Disaggregation of Revenue [Line Items]
Operating revenues, net									$ 35,724	$ 19,671

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Leases - Components and Lease Expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Leases [Abstract]
Fixed operating lease cost	$ 21,619
Variable operating lease, cost	5,884
Total operating lease cost	$ 27,503

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Derivatives - Gains and Losses Recognized Related to Interest Rate Swaps and Commodity Contracts Designated as Cash Flow Hedges (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes				$ (42,290,000)	$ 198,000		$ 17,612,000
(Gain) Loss Included in the Assessment of Effectiveness Reclassfied from AOCI into Income				(2,579,000)	(4,442,000)	[1]	(2,247,000)	[1]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, tax expense (benefit)				1,000,000.0
Gain (Loss) excluded from assessment of effectiveness recognized in OCI using an amortization approach, tax					300,000
Interest rate swaps
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, tax expense (benefit)					(3,600,000)		100,000
Foreign Currency Contracts
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, tax expense (benefit)				0	(3,900,000)		0
Commodity contracts - power
Derivative [Line Items]
(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings	$ 5,300,000	$ (900,000)	$ (10,800,000)
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, tax expense (benefit)					2,000,000.0		(2,500,000)
Interest Expense | Interest rate swaps
Derivative [Line Items]
(Gain) Loss Included in the Assessment of Effectiveness Reclassified from AOCI, tax expense (benefit)				0	700,000		1,100,000
Operating revenues, net | Commodity contracts - power
Derivative [Line Items]
(Gain) Loss Included in the Assessment of Effectiveness Reclassified from AOCI, tax expense (benefit)					2,400,000		1,500,000
Designated as Hedging Instrument
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes				(28,519,000)	9,040,000		17,612,000
Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach				0	452,000		0
(Gain) Loss Included in the Assessment of Effectiveness Reclassfied from AOCI into Income				5,267,000	(497,000)		(2,247,000)
(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings				0	0		(4,193,000)
Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes				(33,503,000)	1,034,000		(396,000)
Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach				0	0		0
Designated as Hedging Instrument | Foreign Currency Contracts
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes				13,904,000	11,169,000		0
Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach				0	0		0
Designated as Hedging Instrument | Commodity contracts - power
Derivative [Line Items]
Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes				(8,920,000)	(3,163,000)		18,008,000
Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach				0	452,000		0
Designated as Hedging Instrument | Interest Expense | Interest rate swaps
Derivative [Line Items]
(Gain) Loss Included in the Assessment of Effectiveness Reclassfied from AOCI into Income				1,896,000	1,307,000		5,507,000
(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings				0	0		(1,270,000)
Designated as Hedging Instrument | Interest Expense | Foreign Currency Contracts
Derivative [Line Items]
(Gain) Loss Included in the Assessment of Effectiveness Reclassfied from AOCI into Income				0	0		0
(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings				0	0		0
Designated as Hedging Instrument | Operating revenues, net | Commodity contracts - power
Derivative [Line Items]
(Gain) Loss Included in the Assessment of Effectiveness Reclassfied from AOCI into Income				3,371,000	(1,804,000)		(7,754,000)
(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings				$ 0	$ 0		$ (2,923,000)

[1] epresents the reclassification of the accumulated foreign currency translation loss for almost the Company’s entire portfolio of solar power plants located in the United Kingdom, as the Company’s sale of these facilities was completed in the second quarter of 2017 as discussed in Note 3. Acquisitions and Divestitures.

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Leases - Summary of Future Commitments before Topic 842 (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Leases [Abstract]
2019	$ 20,002
2020	20,005
2021	20,241
2022	20,410
2023	20,577
Thereafter	331,425
Total	$ 432,660

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Derivatives - Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Nov. 24, 2019	Oct. 16, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Assets	$ 74,949			$ 106,556
Counterparty Netting	(1,413)			(1,201)
Net Derivative Asset	73,536			105,355
Liabilities	136,776			130,608
Counterparty Netting	(1,413)			(1,201)
Derivative Liability	135,363			129,407
Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	16,760			15,228
Counterparty Netting	(941)			(857)
Net Derivative Asset	15,819			14,371
Derivative assets
Derivatives, Fair Value [Line Items]
Assets	58,189			91,328
Counterparty Netting	(472)			(344)
Net Derivative Asset	57,717			90,984
Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	34,910			36,416
Counterparty Netting	(941)			(857)
Derivative Liability	33,969			35,559
Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	101,866			94,192
Counterparty Netting	(472)			(344)
Derivative Liability	101,394			93,848
Interest rate swaps
Derivatives, Fair Value [Line Items]
Derivative Liability		$ 9,800	$ 8,800
Interest rate swaps | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value [Line Items]
Assets	809			7,296
Liabilities	53,651			3,799
Interest rate swaps | Derivatives Designated as Hedging Instruments | Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	0			1,478
Interest rate swaps | Derivatives Designated as Hedging Instruments | Derivative assets
Derivatives, Fair Value [Line Items]
Assets	809			5,818
Interest rate swaps | Derivatives Designated as Hedging Instruments | Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	12,046			465
Interest rate swaps | Derivatives Designated as Hedging Instruments | Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	41,605			3,334
Interest rate swaps | Derivatives Not Designated as Hedging Instruments
Derivatives, Fair Value [Line Items]
Assets	0			0
Liabilities	81,335			122,301
Interest rate swaps | Derivatives Not Designated as Hedging Instruments | Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	0			0
Interest rate swaps | Derivatives Not Designated as Hedging Instruments | Derivative assets
Derivatives, Fair Value [Line Items]
Assets	0			0
Interest rate swaps | Derivatives Not Designated as Hedging Instruments | Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	21,923			34,267
Interest rate swaps | Derivatives Not Designated as Hedging Instruments | Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	59,412			88,034
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value [Line Items]
Assets	373			2,665
Liabilities	946			1,437
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments | Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	349			605
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments | Derivative assets
Derivatives, Fair Value [Line Items]
Assets	24			2,060
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments | Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	631			0
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments | Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	315			1,437
Foreign Currency Contracts | Derivatives Not Designated as Hedging Instruments
Derivatives, Fair Value [Line Items]
Assets	8,596			3,991
Liabilities	844			3,071
Foreign Currency Contracts | Derivatives Not Designated as Hedging Instruments | Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	8,092			3,344
Foreign Currency Contracts | Derivatives Not Designated as Hedging Instruments | Derivative assets
Derivatives, Fair Value [Line Items]
Assets	504			647
Foreign Currency Contracts | Derivatives Not Designated as Hedging Instruments | Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	310			1,684
Foreign Currency Contracts | Derivatives Not Designated as Hedging Instruments | Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	534			1,387
Commodity Price Swap [Member] | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value [Line Items]
Assets	34,309			42,684
Liabilities	0			0
Commodity Price Swap [Member] | Derivatives Designated as Hedging Instruments | Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	1,040			18
Commodity Price Swap [Member] | Derivatives Designated as Hedging Instruments | Derivative assets
Derivatives, Fair Value [Line Items]
Assets	33,269			42,666
Commodity Price Swap [Member] | Derivatives Designated as Hedging Instruments | Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	0			0
Commodity Price Swap [Member] | Derivatives Designated as Hedging Instruments | Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	0			0
Commodity Price Swap [Member] | Derivatives Not Designated as Hedging Instruments
Derivatives, Fair Value [Line Items]
Assets	30,862			49,920
Liabilities	0			0
Commodity Price Swap [Member] | Derivatives Not Designated as Hedging Instruments | Derivative assets, current
Derivatives, Fair Value [Line Items]
Assets	7,279			9,783
Commodity Price Swap [Member] | Derivatives Not Designated as Hedging Instruments | Derivative assets
Derivatives, Fair Value [Line Items]
Assets	23,583			40,137
Commodity Price Swap [Member] | Derivatives Not Designated as Hedging Instruments | Derivative liabilities, current
Derivatives, Fair Value [Line Items]
Liabilities	0			0
Commodity Price Swap [Member] | Derivatives Not Designated as Hedging Instruments | Derivative liabilities
Derivatives, Fair Value [Line Items]
Liabilities	$ 0			$ 0

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Renewable Energy Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment and Operating Lease Right-of-Use Asset, Net	$ 7,405,461
Total renewable energy facilities, net			$ 6,470,026
Right-of-use asset	288,321
ASU 2016-02
Property, Plant and Equipment, Net, by Type [Abstract]
Right-of-use asset		$ 262,100
Solar Energy Systems
Property, Plant and Equipment, Net, by Type [Abstract]
Renewable energy facilities in service	8,584,243
Less accumulated depreciation - renewable energy facilities	(1,191,056)
Property, Plant and Equipment and Operating Lease Right-of-Use Asset, Net	7,393,187
Renewable energy facilities in service			7,298,371
Less accumulated depreciation - renewable energy facilities			(833,844)
Total renewable energy facilities, net			6,464,527
Construction in progress - renewable energy facilities
Property, Plant and Equipment, Net, by Type [Abstract]
Renewable energy facilities in service	$ 12,274
Renewable energy facilities in service			$ 5,499

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Related Parties - Due from Affiliates Due to Affiliates (Details) $ in Thousands, € in Millions		3 Months Ended	12 Months Ended
	Dec. 18, 2019 EUR (€) business MW	Jun. 30, 2018	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)
Related Party Transaction [Line Items]
Due from affiliate			$ 499	$ 196
Due to affiliate			$ 11,510	6,991
X-Elio PV Acquisition
Related Party Transaction [Line Items]
Nameplate capacity (MW) | MW	45		15.1
Acquisition-Related Costs Payable
Related Party Transaction [Line Items]
Amount due to affiliate			$ 1,400
Share Purchase Agreement | X-Elio PV Acquisition
Related Party Transaction [Line Items]
Number of share purchase agreements | business	3
Number of subsidiaries | business	3
Transitional Services Agreement | X-Elio PV Acquisition
Related Party Transaction [Line Items]
Transitional Service Agreement, initial term	3 months
Transitional Service Agreement, extension term	3 months
Operations And Management Agreement | X-Elio PV Acquisition
Related Party Transaction [Line Items]
Service agreement, term	12 months
Consideration for O&M Agreement	€ 1.0		1,100
Brookfield Asset Management | MSA, Base Management Fee
Related Party Transaction [Line Items]
Balance payable to related party				4,200
Payments to affiliates			(22,400)	(14,000)
Brookfield Asset Management | Services and Fees Related to Acquisition
Related Party Transaction [Line Items]
Balance payable to related party			1,400
Brookfield Asset Management | Accrued Standby Fee Interest
Related Party Transaction [Line Items]
Due to affiliate			600
Payments to affiliates			(1,900)	(3,600)
Brookfield Asset Management | Payable for Commodity Contracts
Related Party Transaction [Line Items]
Due to affiliate			500
Brookfield Asset Management | Rent, Office Charges and Other
Related Party Transaction [Line Items]
Due to affiliate			400
Brookfield Asset Management | Corporate Headquarter Leasehold Improvements, Rent and Other Office Charges
Related Party Transaction [Line Items]
Due to affiliate			$ 3,600	2,800
Brookfield Asset Management | Acquisition-Related Costs Payable
Related Party Transaction [Line Items]
Payments to affiliates				$ (4,000)
Affiliated Entity | Credit Support
Related Party Transaction [Line Items]
Percentage of savings realized in transaction		50.00%
Brookfield and Affiliates | X-Elio PV Acquisition
Related Party Transaction [Line Items]
Ownership percentage	50.00%

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Concentration Of Credit Risks (Tables)

12 Months Ended

Dec. 31, 2019

Risks and Uncertainties [Abstract]

Schedules of Major Financial Assets And Major Customers Subject to Concentration of Credit Risk

The following table reflects the balances of the major financial assets that are subject to concentrations of credit risk as of December 31, 2019, and 2018:

	As of December 31,
(In thousands)	2019		2018
Cash and cash equivalents	$	349,500	$	392,809
Accounts receivable, net	167,865		145,161
Derivative assets	73,536		105,355
Total	$	590,901	$	643,325

The following table reflects operating revenues, net for the years ended December 31, 2019, 2018 and 2017, by specific customers exceeding 10% of total net operating revenues:

		Year Ended December 31,
		2019				2018				2017
(In thousands, except for percentages)	Segment	Amount		Percentage		Amount		Percentage		Amount		Percentage
Comisión Nacional de los Mercados y la Competencia1	Regulated Solar and Wind	$	240,714	25.6	%	$	127,912	16.7	%	N/A		N/A
Tennessee Valley Authority2	Wind	93,920		10.0		90,283		11.8		$	79,773	13.1	%
San Diego Gas & Electric3	Solar	N/A		N/A		N/A		N/A		63,905		10.5

———

(1)The Company earned $338.7 million and $186.7 million from the Spanish Electricity System for the years ended December 31, 2019, and 2018, respectively, of which $240.7 million and $127.9 million were through collections from the Comisión Nacional de los Mercados y la Competencia (“CNMC”). These operating revenues were earned within the Regulated Solar and Wind segment and represented 25.6% and 16.7% of the Company’s net consolidated operating revenues for these years, respectively. The CNMC is the state-owned regulator of the Spanish Electricity System who collects the funds payable, mainly from the tariffs to end user customers, and is responsible for the calculation and the settlement of regulated payments.

(2)The Company earned $93.9 million and $90.3 million operating revenues from the Tennessee Valley Authority (“TVA”) for the years ended December 31, 2019, and 2018, respectively. These operating revenues were earned within the Regulated Solar and Wind segment and represented 10.0% and 11.8% of the Company’s net consolidated operating revenues for these years, respectively. The TVA is a corporation wholly-owned by the U.S. government that sells power mainly to wholesale customers in several states in the Southern part on the U.S.

(3)This customer did not exceed 10% of total operating revenue for the year ended December 31, 2019.

Schedule of Amounts Receivable

The amounts receivable from the CNMC and TVA as of December 31, 2019, and 2018, were as follows:

	As of December 31,
(In thousands)	2019		2018
CNMC	$	78,474	$	64,739
TVA	12,722		9,715
Total	$	91,196	$	74,454

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Non-Controlling Interests - Noncontrolling Interest Activity (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018	Oct. 16, 2017
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Beginning		$ 33,495	$ 34,660	$ 165,975
Distributions		(1,220)	(2,458)	(7,818)
Accretion of redeemable non-controlling interest		0	0	(6,729)
Net Income (loss)		(11,983)	9,209	1,596
Reclassification of Invenergy Wind Interest to non-controlling interests				131,822
Cumulative-effect adjustment	[1]				$ 20,106
Consolidation of redeemable non-controlling interests in acquired renewable energy facilities			55,117
Repurchase of redeemable non-controlling interest		(4,753)	(58,014)
Exchange differences			534
Non-cash redemption of redeemable non-controlling interests		7,345
Ending		22,884	$ 33,495	34,660
Repurchase of noncontrolling interest		$ 3,900
TerraForm Subsidiaries | Invenergy Wind
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Ownership percentage by other entities						9.90%
TerraForm Power | Invenergy Wind
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Nonredeemable noncontrolling interest						$ 131,800
Certain Distributed Generation Projects
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Ownership percentage held		100.00%
Redeemable noncontrolling interest
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Cumulative-effect adjustment					$ (4,485)
Capital
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Accretion of redeemable non-controlling interest				$ 6,700

[1] Represents the effect of the adoption of Accounting Standards Update (“ASU”) No. 2014-09, ASU No. 2016-08, ASU No. 2017-12 and ASU No. 2018-02 as of January 1, 2018.

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Related Parties - Brookfield and Terra Agreements (Details) - USD ($)		12 Months Ended
	Oct. 16, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
General and administrative expenses - affiliate		$ 28,070,000	$ 16,239,000	$ 13,391,000
Brookfield Asset Management | Management Services Agreement
Related Party Transaction [Line Items]
Base management fee - year one	$ 2,500,000
Management fee - market capitalization component	0.3125%
Management fee - year two	$ 3,000,000.0
Base management fee thereafter	$ 3,750,000
Share price multiplier (usd per share)	$ 9.52
General and administrative expenses - affiliate		26,800,000	14,600,000
Balance payable to related party		$ 8,600,000	4,200,000
Brookfield Asset Management | Incentive Distribution Rights
Related Party Transaction [Line Items]
Quarterly distribution rights, level one (usd per share)		$ 0.93
Quarterly distribution rights, level two (usd per share)		1.05
Affiliated Entity | Incentive Distribution Rights
Related Party Transaction [Line Items]
Quarterly distribution rights, level one (usd per share)		0.93
Quarterly distribution rights, level two (usd per share)		$ 1.05
Payments for related party transactions		$ 0	$ 0

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table presents the changes in each component of accumulated other comprehensive (loss) income, net of tax:

(In thousands)	Foreign Currency Translation Adjustments		Hedging Activities1		Accumulated Other Comprehensive Income
Balance as of December 31, 2016	$	(22,133)	$	45,045	$	22,912
Net unrealized gain arising during the period (net of tax expense of $3,238 and $2,428, respectively)	10,300		17,612		27,912
Reclassification of net realized loss (gain) into earnings (net of tax benefit of $8,858 and tax expense of $443, respectively)2	14,741		(2,247)		12,494
Other comprehensive income	25,041		15,365		40,406
Accumulated other comprehensive income	2,908		60,410		63,318
Less: Other comprehensive income attributable to non-controlling interests	8,665		5,992		14,657
Plus: Reallocation from non-controlling interests as a result of SunEdison exchange3	(7,655)		7,012		(643)
Balance as of December 31, 2017	(13,412)		61,430		48,018
Cumulative-effect adjustment (net of tax expense of $1,579)4	—		(4,164)		(4,164)
Cumulative-effect adjustment (net of tax expense of $9,357)5	14,524		(5,156)		9,368
Net unrealized (loss) gain arising during the year (net of tax expense of $3,891 and $3,729, respectively)	(9,517)		1,166		(8,351)
Reclassification of net realized gain into earnings (net of zero and $4,938 tax benefit, respectively)	—		(5,410)		(5,410)
Other comprehensive income	(9,517)		(4,244)		(13,761)
Accumulated other comprehensive income	(8,405)		47,866		39,461
Less: Other comprehensive income attributable to non-controlling interests	—		(777)		(777)
Balance as of December 31, 2018	(8,405)		48,643		40,238
Net unrealized gain (loss) arising during the period (net of zero and $978 tax benefit, respectively)	15,652		(42,290)		(26,638)
Reclassification of net realized gain into earnings (net of zero tax impact)	—		(2,579)		(2,579)
Other comprehensive income (loss)	15,652		(44,869)		(29,217)
Accumulated other comprehensive income	7,247		3,774		11,021
Less: Other comprehensive income attributable to non-controlling interests	—		(624)		(624)
Balance as of December 31, 2019	$	7,247	$	4,398	$	11,645

———

(1)See Note 12. Derivatives for additional breakout of hedging gains and losses for interest rate swaps and commodity contracts in a cash flow hedge relationship and the foreign currency contracts designated as hedges of net investments.

(2)The foreign currency translation adjustment amount represents the reclassification of the accumulated foreign currency translation loss for the U.K. Portfolio, as the Company’s sale of this portfolio closed in the second quarter of 2017. The pre-tax amount of $23.6 million was recognized within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

(3)Represents reclassification of accumulated comprehensive (losses) income previously attributed to SunEdison’s non-controlling interest in Terra LLC from non-controlling interests to AOCI as of October 16, 2017, as a result of SunEdison’s exchange of its Class B units in Terra LLC for Class A shares of TerraForm Power as discussed in Note 18. Non-Controlling Interests.

(4)Represents the cumulative-effect adjustment related to the early adoption of ASU 2017-12. See Note 2. Summary of Significant Accounting Policies for additional details.

(5)Represents the cumulative-effect adjustment of deferred taxes stranded in AOCI resulting from the early adoption of ASU No. 2018-02 See Note 2. Summary of Significant Accounting Policies.

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Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information (Unaudited)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly consolidated results of operations for the year ended December 31, 2019 were as follows:

(In thousands, except per share data)	Q1		Q2		Q31		Q42,3
Operating revenues, net	$	225,332	$	255,366	$	253,808	$	206,734
Operating income (loss)	29,104		54,928		40,365		(10,967)
Interest expense, net	86,287		71,041		89,393		51,421
Net loss	(36,057)		(16,827)		(62,313)		(91,388)
Net loss attributable to Class A common stockholders	(8,627)		(3,595)		(54,837)		(81,625)
Weighted average Class A common shares outstanding - basic and diluted	209,142		209,142		209,155		217,608
Net loss per weighted average Class A common share - basic and diluted	$	(0.04)	$	(0.02)	$	(0.26)	$	(0.38)

———

(1)During the third quarter of 2019, the Company recorded corrections related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement resulting in an increase in the previously reported accretion and depreciation expense by $3.3 million and $3.7 million, respectively, as a result of this change.

(2)As discussed in Note 3. Acquisitions and Divestitures, on September 26, 2019, the Company completed the WGL Acquisition representing an approximately 320 MW distributed generation portfolio of renewable energy facilities located in the United States. The below table presents selected financial information for the acquired entities as included in the Company’s results for the year ended December 31, 2019:

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Revenue (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Schedule of Operating Revenues, Net and Disaggregated of Revenue

The following table presents the Company’s operating revenues, net and disaggregated by revenue source:

	Year Ended December 31, 2019								Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Total		Solar		Wind		Regulated Solar and Wind		Total
PPA rental income	$	199,266	$	191,508	$	—	$	390,774	$	198,610	$	192,324	$	—	$	390,934
Commodity derivatives	—		37,054		—		37,054		—		46,287		—		46,287
PPA and market energy revenue	46,740		79,253		97,953		223,946		39,566		54,998		58,742		153,306
Capacity revenue from remuneration programs1	—		—		204,991		204,991		—		—		108,242		108,242
Amortization of favorable and unfavorable rate revenue contracts, net	(8,850)		(31,090)		—		(39,940)		(9,743)		(29,024)		—		(38,767)
Energy revenue	237,156		276,725		302,944		816,825		228,433		264,585		166,984		660,002
Incentive revenue2	79,277		9,414		35,724		124,415		70,533		16,364		19,671		106,568
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	941,240	$	298,966	$	280,949	$	186,655	$	766,570

———

(1)Represents the return related to the Company’s investments associated with its renewable energy facilities in Spain. See Note 2. Summary of Significant Accounting Policies for additional details.

(2)Incentive revenue earned at the Regulated Solar and Wind segment represents the return per MWh generated by the Company’s solar facilities in Spain to recover certain operating expenses. See Note 2. Summary of Significant Accounting Policies for additional details.

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 237,480	$ 248,524
Restricted cash	35,657	27,784
Accounts receivable, net	167,865	145,161
Due from affiliates	499	196
Prepaid expenses	13,514	13,116
Derivative assets, current	15,819	14,371
Deposit on acquisitions	24,831	0
Other current assets	57,682	52,033
Total current assets	553,347	501,185
Renewable energy facilities, net, including consolidated variable interest entities of $3,188,508 and $3,064,675 in 2019 and 2018, respectively		6,470,026
Renewable energy facilities, net, including consolidated variable interest entities of $3,188,508 and $3,064,675 in 2019 and 2018, respectively	7,405,461
Intangible assets, net, including consolidated variable interest entities of $690,594 and $751,377 in 2019 and 2018, respectively	1,793,292	1,996,404
Goodwill	127,952	120,553
Restricted cash	76,363	116,501
Derivative assets	57,717	90,984
Other assets	44,504	34,701
Total assets	10,058,636	9,330,354
Current liabilities:
Current portion of long-term debt and financing lease obligations, including consolidated variable interest entities of $55,089 and $64,251 in 2019 and 2018, respectively	441,951	464,332
Accounts payable, accrued expenses and other current liabilities	178,796	181,400
Due to affiliates	11,510	6,991
Derivative liabilities, current	33,969	35,559
Total current liabilities	666,226	688,282
Long-term debt and financing lease obligations, less current portion, including consolidated variable interest entities of $932,862 and $885,760 in 2019 and 2018, respectively	5,793,431	5,297,513
Operating lease obligations, less current portion, including consolidated variable interest entities of $138,816 in 2019	272,894
Asset retirement obligations, including consolidated variable interest entities of $116,159 and $86,457 in 2019 and 2018, respectively	287,288	212,657
Derivative liabilities	101,394	93,848
Deferred income taxes	194,539	178,849
Other liabilities	112,072	90,788
Total liabilities	7,427,844	6,561,937
Redeemable non-controlling interests	22,884	33,495
Stockholders’ equity:
Class A common stock, $0.01 par value per share, 1,200,000,000 shares authorized, 227,552,105 and 209,642,140 shares issued in 2019, and 2018, respectively	2,276	2,096
Additional paid-in capital	2,512,891	2,391,435
Accumulated deficit	(508,287)	(359,603)
Accumulated other comprehensive income	11,645	40,238
Treasury stock, 1,051,298 and 500,420 shares in 2019 and 2018, respectively	(15,168)	(6,712)
Total TerraForm Power, Inc. stockholders’ equity	2,003,357	2,067,454
Non-controlling interests	604,551	667,468
Total stockholders’ equity	2,607,908	2,734,922
Total liabilities, redeemable non-controlling interests and stockholders’ equity	$ 10,058,636	$ 9,330,354

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Consolidated Statements of Comprehensive Loss (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Statement of Comprehensive Income [Abstract]
Reclassification of net realized loss into earnings, before tax	$ 23.6

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Renewable Energy Facilities

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Renewable Energy Facilities

RENEWABLE ENERGY FACILITIES

Renewable energy facilities, net consists of the following: 

	As of December 31,
(In thousands)	2019		2018
Renewable energy facilities in service, at cost1	$	8,584,243	$	7,298,371
Less accumulated depreciation - renewable energy facilities	(1,191,056)		(833,844)
Renewable energy facilities in service, net	7,393,187		6,464,527
Construction in progress - renewable energy facilities	12,274		5,499
Total renewable energy facilities, net	$	7,405,461	$	6,470,026

———

(1)As discussed in Note 2. Summary of Significant Accounting Policies and Note 8. Leases, on January 1, 2019, the Company recognized $262.1 million right-of-use of assets related to operating leases as a result of the adoption of Topic 842, which is included within renewable energy facilities. The amount of right-of-use of assets as of December 31, 2019 was $288.3 million.

Depreciation expense related to renewable energy facilities was $325.1 million, $270.4 million and $212.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Sale of Assets

On December 20, 2019, the Company sold six distributed generation facilities in the United States, with a combined nameplate capacity of 6.0 MW, for a net consideration of $9.5 million. The Company recognized a net gain of $2.3 million, representing the difference between the net proceeds from the sale and the net carrying amount of assets sold and liabilities extinguished, in the consolidated statement of operations for the year ended December 31, 2019, within Gain on sale of renewable energy facilities.

Impairment Assessment

During the year ended December 31, 2019, the Company identified opportunities to repower two wind power plants in the Northeast with a combined nameplate capacity of 160 MW by replacing certain components of the wind turbines with newer equipment while preserving the existing towers, foundation and balance of plant. The Company views repowering activities as opportunities to increase efficiency and extend the useful lives of existing renewable energy facilities. The Company performed impairment testing for these two wind power plants and did not record any impairment losses since it was

determined that the expected undiscounted cash flows were greater than the net carrying amount of the related renewable energy facilities of $79.4 million as of December 31, 2019. If the Company determines to move forward with the repowering activities for one or both of these wind plants during the year 2020, the Company will revise the estimated remaining useful lives of certain components of the renewable energy facilities that will be replaced in the repowering activities and accelerate the recognition of depreciation expense to no later than the removal date.

The Company had a REC sales agreement expiring on December 31, 2021, with a customer within a distributed generation portfolio, and on March 31, 2018, the customer filed for protection under Chapter 11 of the U.S. Bankruptcy Code. The potential replacement of this contract would likely result in a significant decrease in expected revenues for this operating project. The Company’s analysis indicated that the bankruptcy filing was a triggering event to perform an impairment evaluation, and the carrying amount of $19.5 million as of March 31, 2018 was no longer considered recoverable based on an undiscounted cash flow forecast. The Company estimated the fair value of the operating project at $4.3 million as of March 31, 2018 and recognized an impairment charge of $15.2 million equal to the difference between the carrying amount and the estimated fair value, which is reflected within impairment of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2018. The Company used an income approach methodology of valuation to determine fair value by applying a discounted cash flow method to the forecasted cash flows of the operating project, which was categorized as a Level 3 fair value measurement due to the significance of unobservable inputs. Key estimates used in the income approach included forecasted power and incentive prices, customer renewal rates, operating and maintenance costs and the discount rate.

The Company sold 0.3 MW of residential assets (that were not classified as held for sale as of December 31, 2016) during the third quarter of 2017. These assets did not meet the criteria for held for sale classification as of June 30, 2017 but the Company determined that certain impairment indicators were present and as a result recognized an impairment charge of $1.4 million within impairment of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

No impairment losses were recognized for the twelve months ended December 31, 2019.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements represent the results of TerraForm Power, which consolidates Terra LLC through its controlling interest.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated.

The Company elected not to push-down the application of the acquisition method of accounting to its consolidated financial statements following the consummation of the Merger and the change of control that occurred, as discussed in Note 1. Nature of Operations and Organization.

Reclassifications

Certain prior period amounts that existed within the consolidated balance sheets as of December 31, 2018, have been reclassified to conform to the current period presentation. Specifically, the Company presented the balances of current and non-current derivative assets and liabilities, and prepaid expenses separately on the consolidated balance sheets. Additionally, the

Company presented the balances of current and non-current deferred revenue as components of current and non-current other liabilities, as appropriate.

Use of Estimates

In preparing the consolidated financial statements, the Company uses estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements. Such estimates also affect the reported amounts of revenues, expenses, and cash flows during the reporting period. To the extent there are material differences between the estimates and actual results, the Company’s future results of operations would be affected.

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and money market funds with original maturity periods of three months or less when purchased.

Restricted Cash

Restricted cash consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements and funds held within the Company’s project companies that are restricted for current debt service payments and other purposes in accordance with the applicable debt agreements. These restrictions include: (i) cash on deposit in collateral accounts, debt service reserve accounts and maintenance reserve accounts; and (ii) cash on deposit in operating accounts but subject to distribution restrictions related to debt defaults existing as of the date of the balance sheet. Restricted cash that is not expected to become unrestricted within twelve months from the date of the balance sheet is presented within non-current assets in the consolidated balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are reported on the consolidated balance sheets, including both billed and unbilled amounts, and are adjusted for the allowance for doubtful accounts and any write-offs. The Company establishes an allowance for doubtful accounts to adjust its receivables to amounts considered to be ultimately collectible, and charges to the allowance are recorded within general and administrative expenses or cost of operations, as appropriate, in the consolidated statements of operations. The Company’s allowance for doubtful accounts is based on a variety of factors, including the length of time receivables are past due, significant one-time events, the financial health of its customers, and historical experience. The allowance for doubtful accounts was $1.4 million and $1.6 million as of December 31, 2019, and 2018, respectively, and charges (reductions) to the allowance recorded within general and administrative expenses for the years ended December 31, 2019, 2018 and 2017 were $0.2 million, $0.1 million and $(1.5) million, respectively. Accounts receivable are written off in the period in which the receivable is deemed uncollectible, and collection efforts have been exhausted. There were no write-offs of accounts receivable for the years ended December 31, 2019, 2018, and 2017.

Renewable Energy Facilities

Renewable energy facilities consist of solar generation and storage facilities and wind power plants that are stated at cost. Expenditures for major additions and improvements are capitalized, and minor replacements, maintenance, and repairs are charged to expense as incurred. Depreciation of the Company’s solar and storage facilities is recognized using the straight-line composite method over their estimated useful lives which ranged from 12 to 28 years and 23 to 30 years, as of December 31, 2019 and 2018, respectively. Under this method, the Company’s assets with similar characteristics and estimated useful lives are grouped and depreciated as a single unit. Depreciation of the Company’s wind power plant is calculated based on the major components of wind power plants and is recognized over the estimated periods during which these major components remain in service. The Company’s major components of wind power plants had remaining useful lives ranging from 8 to 36 years. As of December 31, 2019 and 2018, they had a weighted average remaining useful life of 19 and 21 years, respectively.

Construction in-progress represents the cumulative construction costs, including the costs incurred for the purchase of major equipment and engineering costs and any capitalized interest. Once the project achieves commercial operation, the Company reclassifies the amounts recorded in construction in progress to renewable energy facilities in service.

Finite-Lived Intangibles

The Company’s finite-lived intangible assets and liabilities represent revenue contracts, consisting of long-term licensing agreements, power purchase contracts (“PPAs”), and renewable energy credits (“RECs”) that were obtained through third-party acquisitions. The revenue contract intangibles comprise favorable and unfavorable rate PPAs and REC agreements and the in-place value of market-rate PPAs. Intangible assets and liabilities that have determinable estimated lives are amortized on a straight-line basis over those estimated lives. Amortization of favorable and unfavorable rate revenue contracts is recorded within operating revenues, net in the consolidated statements of operations. Amortization expense related to the licensing contracts and in-place value of market-rate revenue contracts is recorded within depreciation, accretion and amortization expense in the consolidated statements of operations. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used up. The amounts and useful lives assigned to intangible assets acquired and liabilities assumed impact the amount and timing of future amortization.

Impairment of Renewable Energy Facilities and Intangibles

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recognized when indicators of impairment are present and the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. The Company review our current activities, changes in the conditions of our renewable energy facilities and the market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a long-lived asset group, generally this is an individual renewable energy project, include a substantial and sustained decline in the trading price of our Common Stock, severe adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in forecasted operating revenues and earnings of our operating projects, and deterioration in the performance of our renewable energy facilities. An impairment charge is measured as the difference between a long lived asset group’s carrying amount and its fair value. The fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets, and present value techniques.

During the year ended December 31, 2018, the Company recognized a $15.2 million non-cash impairment charge within its Solar reporting segment related to an operating project within a distributed generation portfolio due to the bankruptcy of a significant customer. During the year ended December 31, 2017, the Company recognized an impairment charge of $1.4 million, within impairment of renewable energy facilities in the consolidated statements of operations, on its 11.4 MW portfolio of residential rooftop solar assets that was classified as held for sale as of December 31, 2016, and subsequently sold in 2017. See Note 3. Acquisitions and Divestitures and Note 6. Renewable Energy Facilities for further discussion.

Goodwill

The Company evaluates goodwill for impairment at least annually on December 1. The Company performs an impairment test between scheduled annual tests if facts and circumstances indicate that it is more-likely-than-not that the fair value of a reporting unit that has goodwill is less than its carrying value. A reporting unit is either the operating segment level or one level below, which is referred to as a component. The level at which the impairment test is performed requires judgment as to whether the operations below the operating segment constitute a self-sustaining business or whether the operations are similar such that they should be aggregated for purposes of the impairment test. The Company defines its reporting units to be consistent with its operating segments.

The Company may first make a qualitative assessment of whether it is more-likely-than-not that a reporting unit’s fair value is less than its carrying value to determine whether it is necessary to perform the quantitative goodwill impairment test. The qualitative impairment test includes considering various factors, including macroeconomic conditions, industry and market conditions, cost factors, a sustained share price or market capitalization decrease, and any reporting unit specific events. If it is determined through the qualitative assessment that a reporting unit’s fair value is more-likely-than-not greater than its carrying value, the quantitative impairment test is not required. If the qualitative assessment indicates it is more-likely-than-not that a reporting unit’s fair value is not greater than its carrying value, the Company must perform the quantitative impairment test. The Company may also elect to proceed directly to the quantitative impairment test without considering such qualitative factors.

The quantitative impairment test is the comparison of the fair value of a reporting unit with its carrying amount, including goodwill. In accordance with the authoritative guidance over fair value measurements, the Company defines the fair value of a reporting unit as the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. The Company primarily uses the income approach methodology of valuation, which uses the discounted cash flow method to estimate the fair values of the Company’s reporting units. The Company does not believe that a cost approach is relevant to measuring the fair values of its reporting units.

Significant management judgment is required when estimating the fair value of the Company’s reporting units, including the forecasting of future operating results, the discount rates and expected future growth rates that it uses in the discounted cash flow method of valuation, and in the selection of comparable businesses that are used in the market approach. If the estimated fair value of the reporting unit exceeds the carrying value assigned to that unit, goodwill is not impaired. If the carrying value assigned to a reporting unit exceeds its estimated fair value, the Company records an impairment charge based on the excess of the reporting unit’s carrying amount over its fair value. The impairment charge is limited to the amount of goodwill allocated to the reporting unit.

The Company performed a qualitative impairment test for the goodwill balance of $128.0 million, and concluded that the carrying amount of the related reporting units does not exceed its fair value. No goodwill impairment charges were recorded for the years ended December 31, 2019, 2018 and 2017.

Financing Lease Obligations

Certain of the Company’s assets were financed with sale-leaseback arrangements. Proceeds received from a sale-leaseback are treated using the financing method when the sale of the renewable energy facility is not recognizable. A sale is not recognized when the leaseback arrangements include a prohibited form of continuing involvement, such as an option or obligation to repurchase the assets under the Company’s master lease agreements. Under these arrangements, the Company does not recognize any profit until the sale is recognizable, which the Company expects to recognize at the end of the arrangement when the contract is canceled and the initial deposits received are forfeited by the financing party.

The Company is required to make rental payments throughout the leaseback arrangements. These payments are allocated between principal and interest payments using an effective yield method.

Deferred Financing Costs

Financing costs incurred in connection with obtaining senior notes and term financing are deferred and amortized over the maturities of the respective financing arrangements using the effective interest method and are presented as a direct deduction from the carrying amount of the related debt (see Note 10. Long-term Debt for additional details), except for the costs related to the Company’s revolving credit facilities, which are presented as a non-current asset on the consolidated balance sheets within other assets. As of December 31, 2019, 2018 and 2017, the Company had $10.8 million, $6.7 million, and $9.4 million, respectively, of unamortized deferred financing costs related to its revolving credit facilities.

Inventory

Inventory consists of spare parts and is recorded at the lower of the weighted average cost of purchase or net realizable value within other current assets in the consolidated balance sheets. Spare parts are expensed to cost of operations in the consolidated statements of operations or capitalized to renewable energy facilities when installed or used, as appropriate.

Asset Retirement Obligations

Asset retirement obligations are accounted for in accordance with Accounting Standards Codification (“ASC”) 410-20, Asset Retirement Obligations. Retirement obligations associated with renewable energy facilities included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, and for which the timing and/or method of settlement may be conditional on a future event. Asset retirement obligations are recognized at fair value in the period in which they are incurred, and a corresponding asset retirement costs are recognized within the related renewable energy facilities. Over time, the asset retirement cost is depreciated over the estimated useful life of the related renewable energy facility, and the asset retirement obligation is accreted to its expected future value.

The Company generally reviews its asset retirement obligations annually, based on its review of updated cost studies, as necessary, and its evaluation of cost escalation factors. The Company evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant the application of the updated estimates to the asset retirement obligations. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognized as an increase or a decrease in the asset retirement cost to the extent applicable.

Revenue from Contracts with Customers

Adoption of Topic 606

On January 1, 2018, the Company adopted ASU No. 2014-09, Revenue from Contracts with Customers and ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (collectively referred to as “Topic 606”) for all revenue contracts in scope, which primarily included bundled energy and incentive sales through PPAs, individual REC sales, and upfront sales of federal and state incentive benefits recorded. The Company elected to use the contract modification practical expedient for purposes of computing the cumulative-effect adjustment recorded to the balances of stockholders’ equity as of January 1, 2018.

The Company evaluated the impact of Topic 606 as it relates to the individual sale of RECs. In certain jurisdictions, there may be a lag between physical generation of the underlying energy and the transfer of RECs to the customer due to administrative processes imposed by state regulations. Under the Company’s previous accounting policy, revenue was recognized as the underlying electricity was generated if the sale had been contracted with the customer. Based on the framework in Topic 606, for a portion of the existing individual REC sale arrangements where the transfer of control to the customer is determined to occur upon the transfer of the RECs, the Company currently recognizes revenue commensurate with the transfer of RECs to the customer as compared to the generation of the underlying energy under the previous accounting policy. Revenue recognition practices for the remainder of existing individual REC sale arrangements remain the same; that is, revenue is recognized based on the underlying generation of energy because the contracted RECs are produced from a designated facility and control of the RECs transfers to the customer upon generation of the underlying energy. The adoption of Topic 606, as it relates to the individual sale of RECs, resulted in an increase in accumulated deficit on January 1, 2018, of $20.5 million, net of tax, and net of $0.3 million and $4.5 million that were allocated to non-controlling interests and redeemable non-controlling interests, respectively. The adjustments for accumulated deficit and non-controlling interests are reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018, and the redeemable non-controlling interests adjustment is reflected within cumulative-effect adjustment in the redeemable non-controlling interests roll-forward presented in Note 18. Non-controlling Interests.

The Company evaluated the impact of Topic 606 as it relates to the upfront sale of investment tax credits (“ITCs”) through its lease pass-through fund arrangements. The amounts allocated to the ITCs were initially recorded as deferred revenue in the consolidated balance sheets, and subsequently, one-fifth of the amounts allocated to the ITCs was recognized annually as incentives revenue in the consolidated statements of operations based on the anniversary of each solar energy system’s placed-in-service date. The Company concluded that revenue related to the sale of ITCs through its lease pass-through arrangements should be recognized at the point in time when the related solar energy systems are placed in service. Previously, the Company recognized this revenue evenly over the five-year ITC recapture period. The Company concluded that the likelihood of a recapture event related to these assessments is remote. The adoption of Topic 606, as it relates to the upfront sale of ITCs, resulted in a decrease in accumulated deficit on January 1, 2018 of $40.9 million, net of tax, which is reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018. The impact on the Company’s results of operations for the year ended December 31, 2018 resulted in a decrease in non-cash deferred revenue recognition of $16.3 million.

PPA Rental Income

The majority of the Company’s energy revenue is derived from long-term PPAs accounted for as operating leases under ASC 840, Leases. Rental income under these lease agreements is recorded as revenue when the electricity is delivered to the customer. The Company adopted ASC 842, Leases on January 1, 2019, and elected certain of the practical expedients permitted in the issued standard, including the expedient that permits the Company to retain its existing lease assessment and classification.

Solar and Wind PPA Revenue

PPAs that are not accounted for under the scope of leases or derivatives are accounted for under Topic 606. The Company typically delivers bundled goods consisting of energy and incentive products for a singular rate based on a unit of generation at a specified facility over the term of the agreement. In these types of arrangements, the volume reflects total energy generation measured in Kilowatt hours (“kWhs”), which can vary period to period depending on system and resource availability. The contract rate per unit of generation (kWhs) is generally fixed at contract inception; however, certain pricing arrangements can provide for time-of-delivery, seasonal, or market index adjustment mechanisms over time. The customer is invoiced monthly equal to the volume of energy delivered multiplied by the applicable contract rate.

The Company considers bundled energy and incentive products within PPAs to be distinct performance obligations. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the

performance obligation is satisfied under Topic 606. The Company views the sale of energy as a series of distinct goods that is substantially the same and has the same pattern of transfer measured by the output method. Although the Company views incentive products in bundled PPAs to be performance obligations satisfied at a point in time, measurement of satisfaction and transfer of control to the customer in a bundled arrangement coincides with a pattern of revenue recognition with the underlying energy generation. Accordingly, the Company applied the practical expedient in Topic 606 as the right to consideration corresponds directly to the value provided to the customer to recognize revenue at the invoice amount for its standalone and bundled PPA contracts.

Commodity Derivatives

The Company has certain revenue contracts within its wind fleet that are accounted for as derivatives under the scope of ASC 815, Derivatives and Hedging. Amounts recognized within operating revenues, net in the consolidated statements of operations consist of cash settlements and unrealized gains and losses representing changes in fair value for the commodity derivatives that are not designated as hedging instruments. See Note 12. Derivatives for further discussion.

Regulated Solar and Wind Energy Revenue

Regulated solar and wind includes revenue generated by Saeta’s solar and wind operations in Spain, which are subject to regulations applicable to companies that generate production from renewable sources for facilities located in Spain. While Saeta’s Spanish operations are regulated by the Spanish regulator, the Company has determined that the Spanish entities do not meet the criteria of a rate-regulated entity under ASC 980 Regulated Operations, since the rates established by the Spanish regulator are not designed to recover the entity’s costs of providing its energy generation services. Accordingly, the Company applied Topic 606 to recognize revenue for these customer contract arrangements. The Company has distinct performance obligations to deliver electricity, capacity, and incentives which are discussed below.

The Company has a performance obligation to deliver electricity and these sales are invoiced monthly at the wholesale market price (subject to adjustments due to regulatory price bands that reduce market risk). The Company transfers control of the electricity over time and the customer receives and consumes the benefit simultaneously. Accordingly, the Company applied the practical expedient in Topic 606 as the right to consideration corresponds directly to the value provided to the customer to recognize revenue at the invoice amount for electricity sales.

The Company has a stand-ready performance obligation to deliver capacity in the Spanish electricity market in which these renewable energy facilities are located. Proceeds received by the Company from the customer in exchange for capacity are determined by a remuneration on an investment per unit of installed capacity that is determined by the Spanish regulators. The Company satisfies its performance obligation for capacity under a time-based measure of progress and recognizes revenue by allocating the total annual consideration evenly to each month of service.

Regulated Solar and Wind Incentive Revenue

For the Company’s Spanish solar renewable energy facilities, the Company has identified a performance obligation linked to an incentive that is distinct from the electricity and capacity deliveries discussed above. For solar technologies under the Spanish market, the customer makes an operating payment per MWh which is calculated based on the difference of a standard cost and an expected market price, both, determined by the Spanish regulator. The customer is invoiced monthly equal to the volume of energy produced multiplied by the regulated rate. The performance obligation is satisfied when the Company generates electricity from the solar renewable facility. The Company recognizes revenue based on the amount invoiced each month.

Amortization of Favorable and Unfavorable Rate-Revenue Contracts

The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. Intangible amortization of certain revenue contracts acquired in business combinations (favorable and unfavorable rate PPAs and REC agreements) is recognized on a straight-line basis over the remaining contract term. The current period amortization for favorable rate revenue contracts is reflected as a reduction to operating revenues, net, and amortization for unfavorable rate revenue contracts is reflected as an increase to operating revenues, net. See Note 7. Intangible Assets, Net and Goodwill for additional details.

Solar and Wind Incentive Revenue

The Company generates incentive revenue from individual incentive agreements relating to the sale of RECs and performance-based incentives to third-party customers that are not bundled with the underlying energy output. The majority of individual REC sales reflect a fixed quantity, fixed price structure over a specified term. The Company views REC products in these arrangements as distinct performance obligations satisfied at a point in time. Since the REC products delivered to the customer are not linked to the underlying generation of a specified facility, these RECs are recognized into revenue when delivered. The Company typically receives payment within 30 days of invoiced REC revenue.

For certain incentive contract arrangements, the quantity delivered to the customer is linked to a specific facility. The pattern of revenue recognition for these incentive arrangements is recognized over time coinciding with the underlying revenue generation from the related facility.

See Note 4. Revenue for additional disclosures.

Leases

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which primarily changes the lessee’s accounting for operating leases by requiring the recognition of lease right-of-use assets and lease liabilities. The guidance also eliminates previous real estate specific provisions. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842), Targeted Improvements, which amended the standard to give entities another option to apply the requirements of the standard in the period of adoption (January 1, 2019) or Effective Date Method. The Company adopted the new accounting guidance on January 1, 2019 using a modified retrospective approach reflecting the Effective Date Method of adoption in which the Company continued to apply the guidance in ASC 840, Leases to the comparable periods presented in the year of adoption.

The Company made the following elections provided under the standard:

•The package of practical expedients that permits the Company to retain its existing lease assessment and classification;

•The practical expedient that allows the Company to not evaluate existing and expired land easements;

•The practical expedient to not separate non-lease components in power purchase agreements (“PPAs”) in which the Company is the lessor in providing energy, capacity, and incentive products for a bundled fixed rate; and

•The Company elected not to apply the recognition requirements for short-term operating leases, defined as a term of twelve months or shorter, from the commencement date.

The Company evaluated the impact of Topic 842 as it relates to operating leases for land, buildings and equipment for which it is the lessee and reviewed its existing contracts for embedded leases. The adoption of the new standard resulted in the recognition of right-of-use assets and lease liabilities of approximately $262.1 million and $256.0 million, respectively, as of January 1, 2019, for operating leases, whereas the Company’s accounting for finance leases remained substantially unchanged.

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment. Leases with an initial term of twelve months or shorter are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. During the year ended December 31, 2019, the Company did not have any leases with an initial term of less than twelve months.

Operating lease right-of-use assets are included within renewable energy facilities, net, whereas right-of-use liabilities are included within accounts payable, accrued expenses and other current liabilities. Right-of-use assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. As the Company’s leases do not provide an implicit rate, the Company calculated an incremental borrowing rate by leveraging external transactions at comparable entities and internally available information to determine the present value of lease payments. The Company’s leases have remaining lease terms ranging from 5 to 41 years.

        The Company’s lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise any such options. Lease expense is recognized on a straight-line basis over the expected lease term. Although some of the Company’s leases contain lease and non-lease components, the Company applies the practical expedient to account for each lease component and non-lease component as a single lease component. Lease payments include fixed rent and taxes, where applicable, and exclude variable rental payments that include other operating expenses is recognized as incurred. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive

covenants. The following tables outline the different components of operating leases and other terms and conditions of the lease agreements where the Company is the lessee.

As discussed above, a significant portion of the Company’s operating revenues are generated from delivering electricity and related products from owned solar and wind renewable energy facilities under PPAs in which the Company is the lessor. Revenue is recognized when electricity is delivered and is accounted for as rental income under the lease standard. The adoption of ASC 842 did not have an impact on the accounting policy for rental income from the Company’s PPAs in which it is the lessor. The Company elected the package of practical expedients available under ASC 842, which did not require the Company to reassess its lease classification from ASC 840. Additionally, the Company elected the practical expedient to not separate lease and non-lease components for lessors. This election allows energy (lease component) and environmental incentives or renewable energy certificates (non-lease components) under bundled PPAs to be accounted as a singular lease unit of account under ASC 842.

See Note 8. Leases for additional disclosures.

Income Taxes

The Company accounts for income taxes using the liability method, which requires it to use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

The Company reports certain of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company’s financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company’s consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using enacted tax rates that are expected to be in effect when the deferred tax liabilities are expected to be realized or settled. Many factors are considered when assessing the likelihood of future realization of deferred tax assets, including recent earnings within taxing jurisdictions, expectations of future taxable income, the carry forward periods available and other relevant factors. The Company believes it is more likely than not that the future reversal of existing taxable temporary differences will allow the Company to realize deferred tax assets, net of valuation allowances. A valuation allowance is recorded to reduce the net deferred tax assets to an amount that is more-likely-than-not to be realized. Tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties related to uncertain tax benefits as a component of income tax expense. Changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits are recorded to income tax expense in the period such determination is made.

The Company releases the taxes deferred in AOCI as the individual units of account (i.e., derivative instruments in a cash flow hedge or net investment hedge relationships) are terminated, extinguished, sold or substantially liquidated.

Adoption of ASU 2018-02

During the fourth quarter of 2018, the Company early adopted ASU No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income addressing certain stranded income tax effects in AOCI resulting from the U.S. government’s enactment of the Tax Cuts and Jobs Act (the “Tax Act”) on December 22, 2017. The adoption of ASU No. 2018-12 resulted in reclassifying $9.4 million of stranded tax effects on the net unrealized gains on derivatives designated as hedging instruments in a cash flow relationship from AOCI to accumulated deficit. The reclassification is reflected as an increase to accumulated deficit within the cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018, and an increase to the opening balance of AOCI as of January 1, 2018.

Variable Interest Entities

The Company assesses entities for consolidation in accordance with ASC 810. The Company consolidates variable interest entities (“VIEs”) in renewable energy facilities when determined to be the primary beneficiary. VIEs are entities that lack one or more of the characteristics of a voting interest entity (“VOE”). The Company has a controlling financial interest in a VIE when its variable interest or interests provide it with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

VOEs are entities in which (i) the total equity investment at risk is sufficient to enable the entity to finance its activities independently and (ii) the equity holders have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the losses of the entity and the right to receive the residual returns of the entity. The usual condition for a controlling financial interest in a voting interest entity is ownership of a majority voting interest. If the Company has a majority voting interest in a voting interest entity, the entity is consolidated.

For the Company’s consolidated VIEs, the Company has presented on its consolidated balance sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of its consolidated VIEs for which creditors do not have recourse to the Company’s general assets outside of the VIE.

Non-controlling Interests and Hypothetical Liquidation at Book Value (“HLBV”)

Non-controlling interests represent the portion of net assets in consolidated entities that are not owned by the Company and are reported as a component of equity in the consolidated balance sheets. Non-controlling interests in subsidiaries that are redeemable either at the option of the holder or at fixed and determinable prices at certain dates in the future are classified as redeemable non-controlling interests in subsidiaries between liabilities and stockholders’ equity in the consolidated balance sheets. Redeemable non-controlling interests that are currently redeemable or redeemable after the passage of time are adjusted to their redemption value as changes occur. The Company applies the guidance in ASC 810-10 along with the Securities and Exchange Commission (“SEC”) guidance in ASC 480-10-S99-3A in the valuation of redeemable non-controlling interests.

The Company has determined the allocation of economics between the controlling party and the third party for non-controlling interests does not correspond to ownership percentages for certain of its consolidated subsidiaries. In order to reflect the substantive profit sharing arrangements, the Company has determined that the appropriate methodology for determining the value of non-controlling interests is a balance sheet approach using the HLBV method. Under the HLBV method, the amounts reported as non-controlling interest on the consolidated balance sheets represent the amounts the third party investors could hypothetically receive at each balance sheet reporting date based on the liquidation provisions of the respective operating partnership agreements. HLBV assumes that the proceeds available for distribution are equivalent to the unadjusted, stand-alone net assets of each respective partnership, as determined under U.S. GAAP. The third party non-controlling interests in the consolidated statements of operations and statements of comprehensive loss are determined based on the difference in the carrying amounts of non-controlling interests on the consolidated balance sheets between reporting dates, adjusted for any capital transactions between the Company and third party investors that occurred during the respective period. 

Where, prior to the commencement of operating activities for a respective renewable energy facility, HLBV results in an immediate change in the carrying value of non-controlling interests on the consolidated balance sheets due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company defers the recognition of the respective adjustments and recognizes the adjustments in non-controlling interest on the consolidated statements of operations on a straight-line basis over the expected life of the underlying assets giving rise to the respective difference. Similarly, where the Company has acquired a controlling interest in a partnership and there is a resulting difference between the initial fair value of non-controlling interest and the value of non-controlling interest as measured using HLBV, the Company initially records non-controlling interests at fair value and amortizes the resulting difference over the remaining life of the underlying assets.

Contingencies

The Company is involved in conditions, situations or circumstances in the ordinary course of business with possible gain or loss contingencies that will ultimately be resolved when one or more future events occur or fail to occur. If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, that amount will be accrued. When no amount within the range is a better estimate than any other amount, the minimum amount in the range will be accrued. The Company continually evaluates uncertainties associated with loss contingencies and records a charge equal to at least the minimum estimated liability for a loss contingency when both of the following conditions are met: (i) information available prior to the issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements; and (ii) the loss or range of loss can be reasonably estimated. Legal costs are expensed when incurred. Gain contingencies are not recorded until realized or realizable.

Derivative Financial Instruments

Adoption of ASU 2017-12

On January 1, 2018, the Company adopted ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities which primarily resulted in simplification of the assessment of hedge

effectiveness for derivatives designated in a qualifying cash flow relationship, and the periodic recognition of gains and losses related to certain components of AOCI. The Company adopted ASU No. 2017-12 using the modified retrospective transition method resulting in a cumulative-effect adjustment of $4.2 million, net of tax of $1.6 million, representing a decrease in accumulated deficit and AOCI, which is reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018.

Initial Recognition

The Company recognizes its derivative instruments as assets or liabilities at fair value in the consolidated balance sheets on a trade date basis unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated as part of a hedging relationship and the type of hedging relationship.

Derivatives that qualify and are designated for hedge accounting are classified as either hedges of the variability of expected future cash flows to be received or paid related to a recognized asset or liability (cash flow hedges) or hedges of the exposure to foreign currency of a net investment in a foreign operation (net investment hedges).

The Company also uses derivative contracts outside the hedging program to manage foreign currency risk associated with intercompany loans.

Subsequent Measurement

The change in fair value of components included in the effectiveness assessment of derivative instruments designated as cash flow hedges is recognized as a component of OCI and reclassified into earnings on a trade date basis in the period that the hedged transaction affects earnings. The change in fair value of components included in the effectiveness assessment of foreign currency contracts designated as net investment hedges is recorded in cumulative translation adjustments within AOCI and reclassified into earnings when the foreign operation is sold or substantially liquidated.

The change in fair value of derivative contracts intended to serve as economic hedges that are not designated as hedging instruments is reported as a component of earnings in the consolidated statements of operations.

Cash flows from derivative instruments designated as net investment hedges and non-designated derivatives used to manage foreign currency risks associated with intercompany loans are classified as investing activities in the

consolidated statements of cash flows. Cash flows from all other derivative instruments are classified as operating activities in the consolidated statements of cash flows.

Fair Value Measurements

The Company performs fair value measurements defined as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required to be recorded at their fair values, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer restrictions and risk of nonperformance.

In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:

•Level 1: Quoted prices in active markets for identical assets or liabilities;

•Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; or

•Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair values of the assets or liabilities.

The Company maintains various financial instruments recorded at cost in the consolidated balance sheets that are not required to be recorded at fair value. For cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and other current assets, accounts payable and accrued expenses and other current liabilities and due to affiliates, net, the carrying

amount approximates fair value because of the short-term maturity of the instruments. See Note 13. Fair Value of Financial Instruments for disclosures related to the fair value of the Company’s derivative instruments and long-term debt.

Foreign Currency

The Company’s reporting currency is the U.S. dollar. Certain of the Company’s subsidiaries maintain their records in local currencies other than the U.S. dollar, which are their functional currencies. When a subsidiary’s local currency is considered its functional currency, the Company translates its assets and liabilities to U.S. dollars using exchange rates in effect at date of the financial statements and its revenue and expense accounts to U.S. dollars at average exchange rates for the period. Cumulative translation adjustments are reported in AOCI in stockholders’ equity. Cumulative translation adjustments are reclassified from AOCI to earnings only when realized upon sale or upon complete or substantially complete liquidation of an investment in a foreign subsidiary. Transaction gains and losses and changes in fair value of the Company’s foreign exchange derivative contracts not accounted for under hedge accounting are included in results of operations as recognized.

Business Combinations and Acquisitions of Assets

The Company applies the definition of a business in ASC 805, Business Combinations to determine whether it is acquiring a business or a group of assets.

The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, acquisition costs related to business combinations are expensed as incurred.

When the Company acquires a renewable energy business, the purchase price is allocated to (i) the acquired tangible assets and liabilities assumed, primarily consisting of land, plant and long-term debt, (ii) the identified intangible assets and liabilities, primarily consisting of the value of favorable and unfavorable rate PPAs, REC agreements, the licensing contracts and in-place value of market rate PPAs, (iii) non-controlling interests, and (iv) other working capital items based in each case on their fair values. The excess of the purchase price over the estimated fair value of net assets acquired is recorded as goodwill.

The Company generally uses independent appraisers to assist with the estimates and methodologies used such as a replacement cost approach, or an income approach or excess earnings approach. Factors considered by the Company in its analysis include considering current market conditions and costs to construct similar facilities. The Company also considers information obtained about each facility as a result of its pre-acquisition due diligence in estimating the fair value of the tangible and intangible assets and liabilities acquired or assumed. In estimating the fair value, the Company also establishes estimates of energy production, current in-place and market power purchase rates, tax credit arrangements and operating and maintenance costs. A change in any of the assumptions above, which are subjective, could have a significant impact on the results of operations.

The allocation of the purchase price directly affects the following items in the consolidated financial statements:

•The amount of purchase price allocated to the various tangible and intangible assets, liabilities and non-controlling interests on the balance sheet;

•The amounts allocated to the value of favorable and unfavorable rate PPAs and REC agreements are amortized to revenue over the remaining non-cancelable terms of the respective arrangement. The amounts allocated to all other tangible assets and intangibles are amortized to depreciation or amortization expense; and

•The period of time over which tangible and definite-lived intangible assets and liabilities are depreciated or amortized varies, and thus, changes in the amounts allocated to these assets and liabilities will have a direct impact on the Company’s results of operations.

ASC 805 allows the acquirer to report provisional amounts and adjust them for a period of time up to one year after the acquisition date (the “measurement period”) while the Company obtains information about the facts and circumstances that existed as of the acquisition date.

When an acquired group of assets does not constitute a business, the transaction is accounted for as an asset acquisition. The Company recognizes and measures the acquired assets based on the cost of the acquisitions, generally being the consideration transferred to the seller and typically includes the direct transaction costs related to the acquisition. The

Company allocates the total cost of acquisition to the individual assets acquired or liabilities assumed based on their relative fair values generally similar to the allocation of the purchase price in a business combination. No goodwill is recognized in an asset acquisition.

Assets Held for Sale

The Company records assets held for sale at the lower of the carrying value or fair value less costs to sell. The following criteria are used to determine if property is held for sale: (i) management has the authority and commits to a plan to sell the property; (ii) the property is available for immediate sale in its present condition; (iii) there is an active program to locate a buyer and the plan to sell the property has been initiated; (iv) the sale of the property is probable within one year; (v) the property is being actively marketed at a reasonable price relative to its current fair value; and (vi) it is unlikely that the plan to sell will be withdrawn or that significant changes to the plan will be made.

In determining the fair value of the assets less costs to sell, the Company considers factors including current sales prices for comparable assets in the region, recent market analysis studies, appraisals and any recent legitimate offers. If the estimated fair value less costs to sell of an asset is less than its current carrying value, the asset is written down to its estimated fair value less costs to sell. Due to uncertainties in the estimation process, it is reasonably possible that actual results could differ from the estimates used in the Company’s historical analysis. The Company’s assumptions about project sale prices require significant judgment because the current market is highly sensitive to changes in economic conditions. The Company estimates the fair values of assets held for sale based on current market conditions and assumptions made by management, which may differ from actual results and may result in additional impairments if market conditions deteriorate.

When assets are classified as held for sale, the Company does not record depreciation or amortization for the respective renewable energy facilities or intangibles.

At December 31, 2019 and 2018, there were no assets held for sale.

Stock-Based Compensation

Stock-based compensation expense for all share-based payment awards to certain employees who provide services to the Company is based on the estimated grant-date fair value. The Company recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award vesting term. For ratable awards, the Company recognizes compensation costs for all grants on a straight-line basis over the requisite service period of the entire award. The Company recognizes the effect of forfeitures in compensation costs when they occur.

Deferred Compensation Plan

The Company sponsors a retirement saving plan that qualifies as a deferred compensation plan under Section 401(k) of the Internal Revenue Code. Eligible U.S. employees may elect to defer a percentage of their qualified compensation for income tax purposes through payroll deductions, and the Company matches a percentage of the contributions based on employees’ elective deferrals. The Company’s total matching contribution expense under the arrangement was $0.5 million, $0.6 million and $0.5 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Restructuring

The Company accounts for restructuring costs in accordance with ASC 712 and ASC 420, as applicable. In connection with the consummation of the Merger and the relocation of the Company’s headquarters to New York, New York, the Company announced a restructuring plan that went into effect upon the closing of the Merger. The Company recognized $0.1 million and $3.7 million of severance and transition bonus costs related to this restructuring within general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2019, and 2018. Severance and transition bonus payments were $0.4 million and $5.5 million during the years ended December 31, 2019, and 2018.

Recently Adopted Accounting Standards - Additional Guidance Adopted in 2019

In October 2018, the FASB issued ASU No. 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (“SOFR”) Overnight Index Swap (“OIS”) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes. This ASU expands the list of United States (“U.S.”) benchmark interest rates permitted in the application of hedge accounting by adding the SOFR as a permissible U.S. benchmark rate. The Company does not have any derivative instruments

indexed to SOFR as a benchmark interest rate, accordingly, the adoption of ASU No. 2018-16 as of January 1, 2019 did not have an impact on the Company’s consolidated financial statements.

Recently Issued Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), to provide financial statement users with more useful information about the current expected credit losses (“CECL”). This ASU changes how entities measure credit losses on financial instruments and the timing of when such losses are recognized by utilizing a lifetime expected credit loss measurement. The guidance is effective for fiscal years and interim periods within those years beginning after January 1, 2020. The Company does not expect the adoption of Topic 326 to have a material impact on its results of operations.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement. This ASU removes some disclosure requirements, modifies others, and adds some new disclosure requirements. The guidance is effective January 1, 2020, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40) Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. This ASU amends the definition of a hosting arrangement and requires a customer in a cloud computing arrangement that is a service contract to follow the internal use software guidance in ASC 350-402 to determine which implementation costs to capitalize as assets. Capitalized implementation costs are amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. The guidance is effective January 1, 2020, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In October 2018, the FASB issued ASU No. 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities. The amendments in this ASU require reporting entities to consider indirect interests held through related parties under common control for determining whether fees paid to decision makers and service provider are variable interests. These indirect interests should be considered on a proportional basis rather than as the equivalent of a direct interest in its entirety (as currently required in U.S. GAAP). The guidance is effective January 1, 2020, with early adoption permitted. Entities are required to apply the amendments in this guidance retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this ASU simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740, Income Taxes. The amendments also improve consistent application or and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The guidance is effective January 1, 2021, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

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Long-Term Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Long-Term Debt

LONG-TERM DEBT

Long-term debt consisted of the following:

	As of December 31,				Interest Type	Interest Rate (%)1
(In thousands, except rates)	2019		2018				Financing Type
Corporate-level long-term debt2:
Senior Notes due 2023	$	500,000	$	500,000	Fixed	4.25	Senior notes
Senior Notes due 2025	—		300,000		Fixed	N/A	Senior notes
Senior Notes due 2028	700,000		700,000		Fixed	5.00	Senior notes
Senior Notes due 2030	700,000		—		Fixed	4.75	Senior notes
Revolver	—		377,000		Variable	N/A	Revolving loan
Term Loan	—		346,500		Variable	N/A	Term debt
Non-recourse long-term debt:
Permanent financing	3,854,386		3,496,370		Blended3	4.384	Term debt / senior notes
Bridge Facility	474,550		—		Variable	2.91	Term debt
Financing lease obligations	59,533		77,066		Imputed	5.804	Financing lease obligations
Total principal due for long-term debt and financing lease obligations	6,288,469		5,796,936			4.384
Unamortized discounts and premiums, net	(3,509)		(15,913)
Deferred financing costs, net	(49,578)		(19,178)
Less current portion of long-term debt and financing lease obligations	(441,951)		(464,332)
Long-term debt and financing lease obligations, less current portion	$	5,793,431	$	5,297,513

———

(1)As of December 31, 2019.

(2)Represents the debt issued by TerraForm Power Operating, LLC (“Terra Operating LLC”) and guaranteed by Terra LLC and certain subsidiaries of TerraForm Operating LLC other than non-recourse subsidiaries as defined in the relevant debt agreements (except for certain unencumbered non-recourse subsidiaries).

(3)Includes fixed rate debt and variable rate debt. As of December 31, 2019, 38% of this balance had a fixed interest rate and the remaining 62% of the balance had a variable interest rate. The Company entered into interest rate swap agreements to fix the interest rates of a majority of the variable rate permanent financing non-recourse debt (see Note 12. Derivatives).

(4)Represents the weighted average interest rate as of December 31, 2019.

Corporate-level Long-term Debt

Senior Notes

On January 28, 2015, Terra Operating LLC issued $800.0 million of 5.88%senior notes due 2023 at an offering price of 99.214% of the principal amount. On June 11, 2015, Terra Operating LLC issued an additional $150.0 million of 5.875% senior notes due 2023 (collectively, with the $800.0 million initially issued, the “Old Senior Notes due 2023”). The offering price of the additional $150.0 million of notes was 101.5% of the principal amount. On July 17, 2015, Terra Operating LLC issued $300.0 million of 6.125% senior notes due 2025 at an offering price of 100% of the principal amount (the “Senior Notes due 2025”).

On December 12, 2017, Terra Operating LLC issued $500.0 million of 4.25% senior notes due 2023 at an offering price of 100% of the principal amount (the “Senior Notes due 2023”) and $700.00 million of 5.00% senior notes due 2028 at an offering price of 100% of the principal amount (the “Senior Notes due 2028”). Terra Operating LLC used the net proceeds of the Senior Notes due 2023 and the Senior Notes due 2028 to redeem, in full, its Old Senior Notes due 2023, of which $950.0 million remained outstanding, at a redemption price that included a prepayment penalty of $50.7 million, plus accrued and unpaid interest, and to repay $150.0 million of revolving loans outstanding under the Revolver, as described below. As a result of the extinguishment of the Old Senior Notes due 2023, the Company recognized a $72.3 million loss on extinguishment of debt during the year ended December 31, 2017, consisting of the $50.7 million prepayment penalty and the write-off of $21.6 million of unamortized deferred financing costs and debt discounts as of the redemption date.

On October 16, 2019, Terra Operating LLC issued $700.0 million aggregate principal amount of 4.75% senior notes due on January 15, 2030, at an offering price of 100% of the principal amount (the “Senior Notes due 2030” and, together with the Senior Notes due 2023 and the Senior Notes due 2028, the “Senior Notes”), in an unregistered offering pursuant to Rule 144A under the Securities Act. Terra Operating LLC used the net proceeds from the Senior Notes due 2030 to (i) redeem, in full, the Senior Notes due 2025, of which $300.0 million remained outstanding, at a redemption price that included a prepayment penalty of $18.4 million, plus accrued interest, (ii) redeem, in full, the Company’s Term Loan (as defined below), of which $343.9 million remained outstanding plus accrued interest, (iii) redeem, in full, derivative liabilities related to interest rate swaps with hedge counterparties of which $8.8 million remained outstanding, and (iii) pay for the fees and expenses related to the issuance.

The Senior Notes are senior obligations of Terra Operating LLC and are guaranteed by Terra LLC and each of Terra Operating LLC’s subsidiaries that guarantee the Revolver (as defined below) or certain other material indebtedness of Terra Operating LLC or Terra LLC. Each series of the Senior Notes rank equally in right of payment with all existing and future senior indebtedness of Terra Operating LLC, including the Revolver, senior in right of payment to any future subordinated indebtedness of Terra Operating LLC, and effectively subordinated to all borrowings under the Revolver, which are secured by substantially all of the assets of Terra Operating LLC and the guarantors of the Senior Notes.

At its option, Terra Operating LLC may redeem some or all of each series of the Senior Notes at any time or from time to time before their maturity. If Terra Operating LLC elects to redeem the Senior Notes due 2023 prior to October 31, 2022, the Senior Notes due 2028 before July 31, 2027, or the Senior Notes due 2030 before January 15, 2025, Terra Operating LLC would be required to pay a prepayment penalty as set forth in the applicable indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2030 between January 15, 2025 and January 14, 2028, Terra Operating LLC would be required to pay a call premium as set forth in the applicable indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2023, the Senior Notes due 2028, or the Senior Notes due 2030 on or after these respective dates, Terra Operating LLC would be required to pay a redemption price equal to 100% of the aggregate principal amount of the Senior Notes redeemed plus accrued and unpaid interest thereon. If certain change of control triggering events occur in the future, Terra Operating LLC must offer to repurchase all of each series of the Senior Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the repurchase date.

Term Loan

On November 8, 2017, Terra Operating LLC entered into a 5-year $350.0 million senior secured term loan (the “Term Loan”) and used the net proceeds to repay outstanding borrowings under a non-recourse project-level term debt and $50.0 million of revolving loans outstanding under the Revolver. The Term Loan originally bore interest at a rate per annum equal to, at Terra Operating LLC’s option, either (i) a base rate plus a margin of 1.75% or (ii) a reserve adjusted Eurodollar rate plus a margin of 2.75%, and is secured and guaranteed equally and ratably with the Revolver. The Term Loan provided for voluntary prepayments, in whole or in part, subject to notice periods. There were no prepayment penalties or premiums other than customary breakage costs after the six-month anniversary of the closing date. Within the first six months following the closing date, a prepayment premium of 1.00% would apply to any principal amounts that were prepaid. On May 11, 2018, Terra Operating LLC entered into an amendment to the Term Loan, whereby the interest rate was reduced by 0.75% per annum. The Company recognized a $1.5 million loss on extinguishment of debt during the year ended December 31, 2018, as a result of this amendment representing write-offs of certain deferred debt financing costs. On March 8, 2019, the Company entered into interest rate swap agreements with counterparties to hedge the cash flows associated with the interest payments on the entire principal of the Term Loan, paying an average fixed rate of 2.54%. In return, the counterparties agreed to pay the variable interest payments due to the lenders until maturity. On October 17, 2019, Terra Operating LLC repaid, in full, the amounts outstanding, including the accrued interest, under the Term Loan using the proceeds of the offering of the Senior Notes due 2030. The Company recognized a loss on extinguishment of $4.0 million for the year ended December 31, 2019, representing write-offs of deferred debt financing costs.

Revolver

On October 17, 2017, Terra Operating LLC entered into a new senior secured revolving credit facility (the “Revolver”) in an initial amount of $450.0 million, available for revolving loans and letters of credit, and maturing in October 2021. All outstanding amounts originally bore interest at a rate per annum equal to, at Terra Operating LLC’s option, either (i) a base rate plus a margin ranging between 1.25% to 2.00% or (ii) a reserve adjusted Eurodollar rate plus a margin ranging between 2.25% to 3.00%. In addition to paying interest on outstanding principal under the Revolver, Terra Operating LLC is required to pay a standby fee in respect of the unutilized commitments thereunder, payable quarterly in arrears. This standby fee ranges between 0.375% and 0.50% per annum. The Revolver provides for voluntary prepayments, in whole or in part, subject to notice periods. There are no prepayment penalties or premiums other than customary breakage costs. On February 6, 2018, Terra Operating

LLC entered into an amendment to increase the facility limit to $600.0 million. On October 5, 2018, Terra Operating LLC entered into an amendment to (i) reduce the interest rate by 0.75% per annum, and (ii) extend the maturity date of the Revolver to October 2023. The Revolver currently bears interest at a rate equal to, at Terra Operating LLC’s option, either (i) a reserve adjusted Eurodollar rate plus an applicable margin ranging from 1.50% to 2.25% per annum, or (ii) a base rate plus an applicable margin ranging from 0.50% to 1.25% per annum. The Company did not incur additional debt or receive any proceeds in connection with the October 5, 2018 amendment.

Under the Revolver, each of Terra Operating LLC’s existing and subsequently acquired or organized domestic restricted subsidiaries (excluding non-recourse subsidiaries) and Terra LLC are or will become guarantors. The Revolver, each guarantee and any interest rate, currency hedging or hedging of REC obligations of Terra Operating LLC or any guarantor owed to the administrative agent, any arranger or any lender under the Revolver is secured by first priority security interests in (i) all of Terra Operating LLC’s, each guarantor’s and certain unencumbered non-recourse subsidiaries’ assets, (ii) 100% of the capital stock of each of Terra Operating LLC and its domestic restricted subsidiaries and 65% of the capital stock of Terra Operating LLC’s foreign restricted subsidiaries and (iii) all intercompany debt. The Revolver is secured equally and ratably with the Term Loan.

On October 8, 2019, Terra Operating LLC entered into an amendment to the Revolver agreement (the “Upsize Amendment”) whereby (i) the aggregate size of the commitments to make revolving loans (‘‘Revolving Loans’’) under the Revolver was increased by $200.0 million to $800.00 million, shared ratably among the lenders of October 8, 2019, (ii) the aggregate size of the letter of credit facility under the Revolver was increased by $50.0 million to $300.0 million and (iii) the accordion feature of the Revolver, which allows for further increases to the commitments to make Revolving Loans, was set at $150.0 million. Additionally, the Upsize Amendment extended the maturity date of the Revolver by one year to October 5, 2024.

Sponsor Line Agreement

On October 16, 2017, TerraForm Power, Inc. entered into a credit agreement (the “Sponsor Line”) with Brookfield and one of its affiliates. The Sponsor Line establishes a $500.0 million secured revolving credit facility and provides for the lenders to commit to making LIBOR loans to the Company during a period not to exceed three years from the effective date of the Sponsor Line (subject to acceleration for certain specified events). The Company may only use the revolving Sponsor Line credit facility to fund all or a portion of certain funded acquisitions or growth capital expenditures. The Sponsor Line terminates, and all obligations thereunder become payable, no later than October 16, 2022.

Borrowings under the Sponsor Line bear interest at a rate per annum equal to a LIBOR rate determined by reference to the costs of funds for U.S. dollar deposits for the interest period relevant to such borrowing adjusted for certain additional costs, in each case plus 3.00% per annum. In addition to paying interest on outstanding principal under the Sponsor Line, the Company is required to pay a standby fee of 0.50% per annum in respect of the unutilized commitments thereunder, payable quarterly in arrears. The Company is permitted to voluntarily reduce the unutilized portion of the commitment amount and repay outstanding loans under the Sponsor Line at any time without premium or penalty, other than customary “breakage” costs. TerraForm Power’s obligations under the Sponsor Line are secured by first-priority security interests in substantially all assets of TerraForm Power, including 100% of the capital stock of Terra LLC, in each case subject to certain exclusions set forth in the credit documentation governing the Sponsor Line. Under certain circumstances, the Company may be required to prepay amounts outstanding under the Sponsor Line.

During the year ended December 31, 2018, the Company made two draws on the Sponsor Line totaling $86.0 million. The Company used the proceeds to fund the acquisition of Saeta and were repaid in full as of December 31, 2018. The Company did not make any draws on the Sponsor Line during the years ended December 31, 2019, and 2017. See Note 21. Related Parties for details.

Covenants and Cross-defaults 

The terms of the Company’s corporate-level debt agreements and indentures include customary affirmative and negative covenants and provide for customary events of default, which include, among others, nonpayment of principal or interest and failure to timely deliver financial statements, including quarterly financial maintenance covenants for the Revolver. The occurrence of an event of default for one corporate-level debt instrument could also cause a cross-default for the other corporate-level debt instruments, as described below.

Pursuant to both the terms of the Revolver and the Term Loan, a default of more than $75.0 million of indebtedness (other than non-recourse indebtedness, and indebtedness under the Sponsor Line, which is an obligation of the Company),

including under these respective agreements, would result in a cross-default under the respective agreements that would permit the lenders holding more than 50% of the aggregate exposure under each to accelerate any outstanding principal amount of loans, terminate any outstanding letter of credit and terminate the outstanding commitments (as applicable to each).

Pursuant to the terms of the Senior Notes, a default of indebtedness that exceeds the greater of (i) $100.0 million for the Senior Notes due 2023 and Senior Notes due 2028, and $140.0 million for the Senior Notes due 2030, or (ii) 1.5% of the Company’s consolidated total assets (other than non-recourse indebtedness and indebtedness under the Sponsor Line, which is an obligation of TerraForm Power), that is (i) caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period provided in such indebtedness on the date of such default or (ii) results in the acceleration of such indebtedness would give the trustee under the respective indentures or the holders of at least 25% in the aggregate principal amount of the then outstanding Senior Notes under the respective indentures the right to accelerate any outstanding principal amount of loans and terminate the outstanding commitments under the respective indentures.

An event of default of more than $75.0 million of indebtedness under the Revolver, Term Loan and each series of the Senior Notes would trigger an event of default under the Sponsor Line that would permit the lenders to accelerate any outstanding principal amount of loans and terminate the outstanding commitments under the Sponsor Line.

Non-recourse Long-term Debt

Certain subsidiaries of the Company have incurred long-term non-recourse debt obligations related to the renewable energy facilities that those subsidiaries own directly or indirectly. The indebtedness of these subsidiaries is typically secured by the renewable energy facilities or equity interests in subsidiaries that directly or indirectly hold renewable energy facilities with no recourse to TerraForm Power, Terra LLC or Terra Operating LLC other than limited or capped contingent support obligations, which in aggregate are not considered material to the Company’s business and financial condition. In connection with these financings and in the ordinary course of its business, the Company and its subsidiaries observe formalities and operating procedures to maintain each of their separate existence and can readily identify each of their separate assets and liabilities as separate and distinct from each other. As a result, these subsidiaries are legal entities that are separate and distinct from each of TerraForm Power, Terra LLC, Terra Operating LLC and the guarantors under the Senior Notes due 2023, the Senior Notes due 2028, the Senior Notes due 2030, the Revolver and the Sponsor Line.

2019 United States Project Financings

On May 29, 2019, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement of $104.1 million senior secured term loan facility, and secured by approximately 137.7 MW of distributed generation solar power facilities located in the U.S. that are owned by certain subsidiaries of the Company. The Company used the net proceeds of this debt to repay a portion of the Revolver and general corporate purposes. The debt bears interest at a rate per annum equal to three month LIBOR plus an applicable margin of 200 basis points that increases by 12.5 basis points every four years until maturity. The debt matures on May 26, 2034, and amortizes on a fifteen-year sculpted amortization schedule. The Company entered into interest rate swap agreements with counterparties to hedge the interest payments associated with the debt, paying a fixed rate of 2.3%. In return, the counterparties agreed to pay the variable interest payments to the lenders.

On August 30, 2019, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement issuing $131.0 million of 3.2% senior notes secured by approximately 111 MW of utility-scale wind power plants located in the United States that are owned by certain subsidiaries of the Company. The Company used the net proceeds of this debt to repay a portion of the balance outstanding under the Revolver. The senior secured notes mature on July 2, 2032 and amortize on an approximately thirteen-year sculpted amortization schedule.

On September 25, 2019, one of the Company’s subsidiaries entered into a $475.0 million new non-recourse senior term loan (“Bridge Facility”) secured by the approximately 320 MW portfolio of distributed generation power facilities located in the United States that were acquired from subsidiaries of AltaGas. The Bridge Facility bears interest at a rate per annum equal to LIBOR plus an applicable margin of 100 basis points for the first six months, 150 basis points for the following six months and 175 basis points thereafter. The Company used the net proceeds of this debt to fund a portion of the purchase price of the WGL Acquisition. See Note 3. Acquisitions and Divestitures for additional details. The Bridge Facility matures on September 24, 2020. The Company has a one-year extension option and intends, through its subsidiaries, to complete a refinancing of the balance on a long-term basis before maturity in a series of two or more transactions. The balance, net of a principal repayment and unamortized deferred financing costs, is included within non-current liabilities in the consolidated balance sheets.

On November 25, 2019, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement issuing $171.5 million of 3.55% senior notes secured by approximately 200.6 MW utility-scale wind power plants located in the United States. The Company used the net proceeds of this debt to (i) redeem, in full, the outstanding balance of the non-recourse project term debt previously incurred by the subsidiary, of which $69.1 million remained outstanding plus accrued and unpaid interest, (ii) redeem, in full, derivative liabilities related to interest rate swaps with hedge counterparties of which $9.8 million remained outstanding and (iii) pay for the fees and expenses related to the issuance. The Company used the remaining proceeds for general corporate purposes. As a result of the extinguishment of the project-level debt, the Company recognized a $0.3 million loss on extinguishment of debt during the year ended December 31, 2019, representing the write-off of unamortized debt discount as of the redemption date. The senior secured notes mature on May 1, 2039, and amortize on a twenty-year amortization schedule.

2019 Spain Project Financings

On December 10, 2019, five of the Company’s subsidiaries completed a €235.8 million refinancing agreement (equivalent to $264.4 million at the closing date) of certain non-recourse indebtedness associated with 236.0 MW utility-scale wind plants located in Spain (the “Spanish Wind Term Loans”). The Spanish Wind Term Loans bear interest at a rate per annum equal to three months Euribor plus an applicable margin of 165 basis points that increases by 20 basis points every five years throughout maturity. The Spanish Wind Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through December 2033. The Company entered into interest rate swap agreements with counterparties to hedge approximately 80% of the cash flows associated with the debt, paying a fixed rate of 1.55%. In return, the counterparties agreed to pay the variable interest payments to the lenders. The Company used the net proceeds of the refinancing to fund a portion of the purchase price of the X-Elio Acquisition.

On December 27, 2019, one of the Company’s subsidiaries completed a €213.6 million refinancing agreement of certain non-recourse indebtedness, representing an upsize of approximately €42.0 million (equivalent to $239.5 million and $47.1 million at the closing date, respectively), of certain non-recourse indebtedness associated with approximately 50.0 MW concentrated solar power facility located in Spain (the “Spanish Solar Term Loans”). The Spanish Solar Term Loans consist of €146.4 million variable-rate tranche and €67.2 million fixed-rate tranche (equivalent to $164.2 million and $75.3 million, respectively). The variable-rate tranche bears interest at a rate per annum equal to three months Euribor plus an applicable margin of 190 basis points that increases by 20 basis points every five years throughout the maturity in December of 2033. The fixed-rate tranche bears interest at a rate of 2.55% and matures on June 30, 2035. The Spanish Solar Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through 2035. The Company entered into interest rate swap agreements with counterparties to hedge approximately 80% of the variable cash flows of the debt, paying an average fixed rate of 3.70%. In return, the counterparty agreed to pay the variable interest payments to the lenders. The Company used the net proceeds of the refinancing for general corporate purposes.

2019 Uruguay Project Financing

On April 30, 2019, two of the Company’s subsidiaries completed a $204.0 million refinancing agreements of certain non-recourse indebtedness, representing a net upsize of approximately $57.5 million, associated with the Company’s 95 MW of utility-scale wind plants located in Uruguay (the “Uruguay Term Loans”). The Uruguay Term Loans consist of a $103.0 million Tranche A loan, a new $72.0 million Tranche B loan, and an additional $29.0 million senior secured term loan. Approximately 46% of the combined principal amount of the Uruguay Term Loans bears a fixed interest rate of 2.6%, and the remainder bears interest at a rate per annum equal to six-month U.S. LIBOR plus an applicable margin that ranges from 1.94% to 2.94%. The Uruguay Term Loans amortize on a sculpted amortization schedule through their respective maturity dates through December 2035. The Company entered into interest rate swap agreements with a counterparty to hedge greater than 90% of the cash flows associated with the variable portion of the debt, paying a fixed rate of 2.78%. In return, the counterparty agreed to pay the variable interest payments to the lenders. The net proceeds of the refinancing were used to pay down a portion of the Revolver and general corporate purposes.

Indebtedness Assumed on Acquisition

In connection with the X-Elio Acquisition, the Company assumed $151.7 million of project-level debt secured by the renewable energy facilities of the related entities. The average interest rates applicable to this assumed indebtedness was 2.8%. As of December 31, 2019, the Company obtained all required change of control consents from the lenders.

Financing Lease Obligations

In certain transactions, the Company accounts for the proceeds of sale-leasebacks as financings, which are typically secured by the renewable energy facility asset and its future cash flows from energy sales, with no recourse to Terra LLC or Terra Operating LLC under the terms of the arrangement.

Non-recourse Debt Defaults

As of December 31, 2019 and December 31, 2018, the Company reclassified $159.3 million and $166.4 million, respectively, of non-recourse long-term indebtedness, net of unamortized deferred financing costs and debt discounts, to current in the consolidated balance sheets due to defaults remaining as of the respective financial statements issuance dates. The defaults as of December 31, 2019 primarily consisted of indebtedness of the Company’s renewable energy facility in Chile. The Company continues to amortize deferred financing costs and debt discounts over the maturities of the respective financing agreements as before the violations, since the Company believes there is a reasonable likelihood that it will be, in due course, able to successfully negotiate waivers with the lenders and/or cure existing defaults. The Company’s management based this conclusion on (i) its past history of obtaining waivers and/or forbearance agreements with lenders, (ii) the nature and existence of active negotiations between the Company and the respective lenders to secure waivers, (iii) the Company’s timely servicing of these debt instruments and (iv) the fact that no non-recourse financing has been accelerated to date and no project-level lender has notified the Company of such lenders election to enforce project security interests.

See Note 5. Cash and Cash Equivalents for discussion of corresponding restricted cash reclassifications to current as a result of these defaults.

Modification and Extinguishment of Debt

Net loss on modification and extinguishment of debt includes prepayment penalties, the write-off of unamortized deferred financing costs and debt premiums or discounts, costs incurred in a debt modification that are not capitalized as deferred financing costs, other costs incurred in relation to debt extinguishment, and any gain from the redemption of debt below its carrying amount. Loss on modification and extinguishment of debt, net in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, were attributable to the following:

	Year Ended December 31,
(In thousands)	2019		2018		2017
Senior Notes due 20251	$	22,827	$	—	$	—
Old Senior Notes due 20231	—		—		72,277
Term Loan1	4,006		1,480		—
The Old Revolver2	—		—		8,822
Non-recourse wind project financing in the U.S.1	313		—		—
Non-recourse wind project financing in Spain1	3,949		—		—
Solar financing lease obligation in the U.S.3	(4,142)		—		—
Total loss on modification and extinguishment of debt, net	$	26,953	$	1,480	$	81,099

———

(1)See above for additional details.

(2)The Company recognized a loss on modification and extinguishment of debt as a result of the reduction of the borrowing capacity of the old revolving credit facility (the “Old Revolver”) and its termination during the year ended December 31, 2017.

(3)The Company recognized a net gain on extinguishment of debt due to the redemption of certain financing lease obligations within the distributed generation Solar portfolio. The difference between the cash paid to redeem the obligations and the carrying amount as of the date of extinguishment was recognized as a loss on extinguishment of debt in the consolidated statements of operations.

Minimum Lease Payments

The aggregate amounts of minimum lease payments on the Company’s financing lease obligations are $59.5 million. Contractual obligations for the years 2020 through 2024 and thereafter, are as follows:

(In thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Minimum lease obligations1	$	3,091	$	3,171	$	3,126	$	4,310	$	2,933	$	42,902	$	59,533

———

(1)Represents the minimum lease payment due dates for the Company’s financing lease obligations and does not reflect the reclassification of $9.8 million of financing lease obligations to current as a result of debt defaults under certain of the Company’s non-recourse financing arrangements.

Maturities

The aggregate contractual principal payments of long-term debt due after December 31, 2019, excluding financing lease obligations and amortization of debt deferred financing costs, as stated in the financing agreements, are as follows:

(In thousands)	20202		2021		2022		2023		2024		Thereafter		Total
Maturities of long-term debt1	$	742,664	$	273,160	$	437,168	$	770,276	$	279,648	$	3,726,020	$	6,228,936

———

(1)Represents the contractual principal payment due dates for the Company’s long-term debt and does not reflect the reclassification of $159.3 million of long-term debt, net of unamortized deferred financing costs of $5.7 million, to current due to debt defaults that existed as of the date of the issuance of the financial statements (see above for additional details) as of December 31, 2019.

(2)Includes the $474.6 million Bridge Facility maturing on September 24, 2020. The Company has a one-year extension option and intends, through its subsidiaries, to complete a refinancing of the balance on a long-term basis prior to maturity. The balance, net of unamortized deferred financing costs, is included within non-current liabilities in the consolidated balance sheets.

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Non-Controlling Interests

12 Months Ended

Dec. 31, 2019

Noncontrolling Interest [Abstract]

Non-Controlling Interests

NON-CONTROLLING INTERESTS

Non-controlling Interests

Non-controlling interests represent the portion of net assets in consolidated entities that are not owned by the Company in renewable energy facilities.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act, which enacted major changes to the U.S. tax code, including a reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Since the 21% rate enacted in December 2017 went into effect on January 1, 2018, the HLBV methodology utilized by the Company to determine the value of its non-controlling interests began to use the new rate on that date. The HLBV method is a point in time estimate that utilizes inputs and assumptions in effect at each balance sheet date based on the liquidation provisions of the respective operating partnership agreements. For the year ended December 31, 2018, $151.2 million of the decline in the non-controlling interests balance and a corresponding allocation of net loss attributable to non-controlling interests was driven by this reduction in the tax rate used in the HLBV methodology used by the Company. In the calculation of the carrying values through HLBV, the Company allocated significantly lower amounts to certain non-controlling interests (i.e., tax equity investors) in order to achieve their contracted after-tax rate of return as a result of the reduction of the federal income tax rate from 35% to 21% as specified in the Tax Act.

Redeemable Non-controlling Interests

Non-controlling interests in subsidiaries that are redeemable either at the option of the holder or at fixed and determinable prices at certain dates are classified as redeemable non-controlling interests in subsidiaries between liabilities and stockholders’ equity in the consolidated balance sheets. The redeemable non-controlling interests in subsidiaries balance is determined using the hypothetical liquidation at book value method for the VIE funds or allocation of share of income or losses in other subsidiaries subsequent to initial recognition; however, the non-controlling interests balance cannot be less than the estimated redemption value.

The following table presents the activity of the redeemable non-controlling interests balance for the years ended December 31, 2019, 2018 and 2017:

(In thousands)	Redeemable Non-controlling Interests
Balance as of December 31, 2016	$	165,975
Distributions	(7,818)
Accretion	6,729
Net income	1,596
Reclassification of Invenergy Wind Interest to non-controlling interests1	(131,822)
Balance as of December 31, 2017	34,660
Cumulative-effect adjustment2	(4,485)
Distributions	(2,458)
Consolidation of redeemable non-controlling interests in acquired renewable energy facilities	55,117
Repurchases of redeemable non-controlling interests, net	(58,014)
Net income	9,209
Exchange differences	(534)
Balance as of December 31, 2018	33,495
Distributions	(1,220)
Repurchases of redeemable non-controlling interests, net3	(4,753)
Non-cash redemption of redeemable non-controlling interests	7,345
Net loss	(11,983)
Balance as of December 31, 2019	$	22,884

———

(1) During the year ended December 31, 2017, the Company recorded $6.7 million adjustment to the value of the Invenergy Wind redeemable non-controlling interest, representing the excess of the future redemption value over its carrying amount based on the SEC guidance in ASC 480-10-S99-3A. Historically, the Company was accreting the redemption value of the Invenergy Wind redeemable non-controlling interest over the redemption period using the straight-line method and accretion adjustments were recorded against additional paid-in capital. As part of the Settlement Agreement, the Option Agreement between Terra LLC and Sun Edison LLC with respect to Invenergy Wind’s remaining 9.9% interest in certain subsidiaries of the Company was rejected upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017. As a result, the Company is no longer obligated to perform on its Option Agreement, and as of October 16, 2017, the Invenergy Wind non-controlling interest amount of $131.8 million was no longer considered redeemable and was reclassified to non-controlling interests as of such date. The redemption adjustments recorded in additional paid-in capital will remain in additional paid-in capital.

(2)See discussion in Note 2. Summary of Significant Accounting Policies regarding the Company’s adoption of ASU No. 2014-09 and ASU No. 2016-08 as of January 1, 2018.

(3)During the year-ended December 31, 2019, the Company purchased the tax equity investors’ interests in certain distributed generation projects in the United States for a combined consideration of $3.9 million, which resulted in increasing the Company’s ownership interest in the related projects to 100%. The difference between the consideration paid and the carrying amounts of the non-controlling interests was recorded as an adjustment to additional paid-in capital within Purchase of (redeemable) non-controlling interests in the consolidated statement of stockholders’ equity.

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Other Financial Information

12 Months Ended

Dec. 31, 2019

Other Liabilities [Abstract]

Other Financial Information

OTHER FINANCIAL INFORMATION

Other current assets presented in the consolidated balance sheets consisted of the following:

	As of December 31,
(In thousands)	2019		2018
Taxes receivable	$	14,435	$	18,798
Indemnity receivable	15,229		15,348
Spare parts inventory	266		7,562
Purchased solar renewable energy credits	5,019		—
Due from financial institutions	6,299		—
Due from service provider	8,212		—
Note receivable from public utility company	4,187		1,027
Miscellaneous	4,035		9,298
Total other current assets	$	57,682	$	52,033

Other liabilities presented in the consolidated balance sheets consisted of the following:

	As of December 31,
(In thousands)	2019		2018
Energy tracking accounts payable	$	71,277	$	38,993
Intangible liabilities	15,864		18,883
Deferred revenue	9,388		12,090
Due to service provider	4,484		4,587
Miscellaneous	11,059		16,235
Total other non-current liabilities	$	112,072	$	90,788

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Acquisitions and Divestitures - Pro Forma Supplementary Data (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
WGL Acquisition
Business Acquisition [Line Items]
Total operating revenues, net	$ 1,011,526	$ 831,145
Net loss	$ (214,280)	(185,392)
Saeta Yield
Business Acquisition [Line Items]
Total operating revenues, net		950,992
Net loss		$ (143,903)

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Other Financial Information - Other Non-Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Other Liabilities [Abstract]
Energy tracking accounts payable	$ 71,277	$ 38,993
Intangible liabilities	15,864	18,883
Deferred revenue	9,388	12,090
Due to service provider	4,484	4,587
Miscellaneous	11,059	16,235
Total other non-current liabilities	$ 112,072	$ 90,788

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Long-Term Debt - Debt Extinguishment (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net	$ (31,100)	$ (26,953)	$ (1,480)	$ (81,099)
Senior Notes due 2025
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		(22,827)	0	0
Senior Notes due 2023
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		0	0	(72,277)
Term Loan
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		(4,006)	(1,480)	0
Old Revolver
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		0	0	(8,822)
Non-recourse Wind Project Financing | United States
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		(313)	0	0
Non-recourse Wind Project Financing | Spain
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		(3,949)	0	0
Solar Finance Lease Obligations
Extinguishment of Debt [Line Items]
(Gain) loss on modification and extinguishment of debt, net		$ (4,142)	$ 0	$ 0

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Stockholders' Equity - Dividends (Details) - $ / shares		3 Months Ended									12 Months Ended
	Oct. 06, 2017	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity [Abstract]
Dividends declared (usd per share)	$ 1.94	$ 0.2014	$ 0.2014	$ 0.2014	$ 0.2014	$ 0.19	$ 0.19	$ 0.19	$ 0.19	$ 1.94	$ 0.8056	$ 0.7600	$ 1.9400

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Long-Term Debt - Revolver (Details) - Line of Credit - USD ($)	Oct. 08, 2019	Oct. 05, 2018	Oct. 17, 2017	Oct. 16, 2017	Feb. 06, 2018
Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 800,000,000.00
Increase in borrowing capacity	200,000,000.0
Revolver accordion feature	$ 150,000,000.0
Debt instrument extension term	1 year
Revolving Credit Facility | Revolver
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 450,000,000.0		$ 600,000,000.0
Interest rate decrease		0.75%
Percentage of domestic entities' capital stock			100.00%
Percentage of foreign entities' capital stock			65.00%
Revolving Credit Facility | Revolver | Base Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%	1.25%
Revolving Credit Facility | Revolver | Base Rate | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate		1.25%	2.00%
Revolving Credit Facility | Revolver | Eurodollar | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate		1.50%	2.25%
Revolving Credit Facility | Revolver | Eurodollar | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate		2.25%	3.00%
Revolving Credit Facility | Revolver | LIBOR
Debt Instrument [Line Items]
Standby fee				50.00%
Revolving Credit Facility | Revolver | LIBOR | Minimum
Debt Instrument [Line Items]
Standby fee			0.375%
Revolving Credit Facility | Revolver | LIBOR | Maximum
Debt Instrument [Line Items]
Standby fee			0.50%
Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 300,000,000.0
Increase in borrowing capacity	$ 50,000,000.0

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Summary of Significant Accounting Policies - Other Narrative and Adoption of ASU (Details) - USD ($) $ in Thousands			12 Months Ended
		Jan. 01, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use asset			$ 288,321
Operating lease liability			$ 291,032
Remaining lease term			17 years 7 months 6 days
Reclassification from AOCI to retained earnings for stranded tax effect		$ 9,400
Cumulative Effect of New Accounting Principle in Period of Adoption	[1]	(20,106)
Matching contribution expense			$ 500	$ 600	$ 500
Employee Severance
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Restructuring charges			100	3,700
Payments for restructuring charges			$ 400	$ 5,500
AOCI Attributable to Parent
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption	[1]	(5,193)
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Remaining lease term			5 years
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Remaining lease term			41 years
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use asset						$ 262,100
Operating lease liability						$ 256,000
ASU 2017-12 | AOCI Attributable to Parent
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption		4,164
Cumulative-effect adjustment, tax		$ 1,600

[1] Represents the effect of the adoption of Accounting Standards Update (“ASU”) No. 2014-09, ASU No. 2016-08, ASU No. 2017-12 and ASU No. 2018-02 as of January 1, 2018.

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Income Taxes - Components of Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Federal, State and Local, Tax Expense (Benefit) [Abstract]
Current federal	$ 145	$ (461)	$ (45)
Current state and local	134	323	95
Current foreign	4,636	2,739	220
Current Total expense (benefit)	4,915	2,601	270
Current tax expense in equity	0	0	0
Current Total tax expense (benefit) including equity effect	4,915	2,601	270
Deferred Federal, State and Local, Tax Expense (Benefit) [Abstract]
Deferred federal	4,728	(18,301)	(20,489)
Deferred state and local	3,197	(4,376)	(1,211)
Deferred foreign	(942)	7,786	1,789
Deferred Total expense (benefit)	6,983	(14,891)	(19,911)
Deferred tax expense in equity	(978)	2,826	14,081
Deferred Total tax expense (benefit) including equity effect	6,005	(12,065)	(5,830)
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Total federal	4,873	(18,762)	(20,534)
Total state and local	3,331	(4,053)	(1,116)
Total foreign	3,694	10,525	2,009
Total expense (benefit)	11,898	(12,290)	(19,641)
Total Tax expense in equity	(978)	2,826	14,081
Total tax expense (benefit) including equity effect	$ 10,920	$ (9,464)	$ (5,560)

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Acquisitions and Divestitures - Acquisition of MW Distributed Generation Assets, Portfolio and Acquisition Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) numberOfAssets MW	Dec. 31, 2018 USD ($) business MW	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Acquisition costs	$ 4,700	$ 14,600
Acquisition costs - affiliate	$ 920	$ 6,925	$ 0
Solar Distributed Generation Portfolio
Business Acquisition [Line Items]
Nameplate capacity (MW) | MW		6.1
Number Of generating facilities acquired | business		6
Purchase price net of cash acquired		$ 4,100
Distributed Generation Facilities
Business Acquisition [Line Items]
Nameplate capacity (MW) | MW	15.1
Number Of generating facilities acquired | numberOfAssets	4
Purchase price net of cash acquired	$ 24,000

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Debt

Long-term debt consisted of the following:

	As of December 31,				Interest Type	Interest Rate (%)1
(In thousands, except rates)	2019		2018				Financing Type
Corporate-level long-term debt2:
Senior Notes due 2023	$	500,000	$	500,000	Fixed	4.25	Senior notes
Senior Notes due 2025	—		300,000		Fixed	N/A	Senior notes
Senior Notes due 2028	700,000		700,000		Fixed	5.00	Senior notes
Senior Notes due 2030	700,000		—		Fixed	4.75	Senior notes
Revolver	—		377,000		Variable	N/A	Revolving loan
Term Loan	—		346,500		Variable	N/A	Term debt
Non-recourse long-term debt:
Permanent financing	3,854,386		3,496,370		Blended3	4.384	Term debt / senior notes
Bridge Facility	474,550		—		Variable	2.91	Term debt
Financing lease obligations	59,533		77,066		Imputed	5.804	Financing lease obligations
Total principal due for long-term debt and financing lease obligations	6,288,469		5,796,936			4.384
Unamortized discounts and premiums, net	(3,509)		(15,913)
Deferred financing costs, net	(49,578)		(19,178)
Less current portion of long-term debt and financing lease obligations	(441,951)		(464,332)
Long-term debt and financing lease obligations, less current portion	$	5,793,431	$	5,297,513

———

(1)As of December 31, 2019.

(2)Represents the debt issued by TerraForm Power Operating, LLC (“Terra Operating LLC”) and guaranteed by Terra LLC and certain subsidiaries of TerraForm Operating LLC other than non-recourse subsidiaries as defined in the relevant debt agreements (except for certain unencumbered non-recourse subsidiaries).

(3)Includes fixed rate debt and variable rate debt. As of December 31, 2019, 38% of this balance had a fixed interest rate and the remaining 62% of the balance had a variable interest rate. The Company entered into interest rate swap agreements to fix the interest rates of a majority of the variable rate permanent financing non-recourse debt (see Note 12. Derivatives).

(4)Represents the weighted average interest rate as of December 31, 2019.

Schedule of Extinguishment of Debt

Loss on modification and extinguishment of debt, net in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, were attributable to the following:

	Year Ended December 31,
(In thousands)	2019		2018		2017
Senior Notes due 20251	$	22,827	$	—	$	—
Old Senior Notes due 20231	—		—		72,277
Term Loan1	4,006		1,480		—
The Old Revolver2	—		—		8,822
Non-recourse wind project financing in the U.S.1	313		—		—
Non-recourse wind project financing in Spain1	3,949		—		—
Solar financing lease obligation in the U.S.3	(4,142)		—		—
Total loss on modification and extinguishment of debt, net	$	26,953	$	1,480	$	81,099

———

(1)See above for additional details.

(2)The Company recognized a loss on modification and extinguishment of debt as a result of the reduction of the borrowing capacity of the old revolving credit facility (the “Old Revolver”) and its termination during the year ended December 31, 2017.

(3)The Company recognized a net gain on extinguishment of debt due to the redemption of certain financing lease obligations within the distributed generation Solar portfolio. The difference between the cash paid to redeem the obligations and the carrying amount as of the date of extinguishment was recognized as a loss on extinguishment of debt in the consolidated statements of operations.

Aggregate Minimum Lease Payments for Financing Lease Obligations

The aggregate amounts of minimum lease payments on the Company’s financing lease obligations are $59.5 million. Contractual obligations for the years 2020 through 2024 and thereafter, are as follows:

(In thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Minimum lease obligations1	$	3,091	$	3,171	$	3,126	$	4,310	$	2,933	$	42,902	$	59,533

———

(1)Represents the minimum lease payment due dates for the Company’s financing lease obligations and does not reflect the reclassification of $9.8 million of financing lease obligations to current as a result of debt defaults under certain of the Company’s non-recourse financing arrangements.

Schedule of Maturities of Long-term Debt

The aggregate contractual principal payments of long-term debt due after December 31, 2019, excluding financing lease obligations and amortization of debt deferred financing costs, as stated in the financing agreements, are as follows:

(In thousands)	20202		2021		2022		2023		2024		Thereafter		Total
Maturities of long-term debt1	$	742,664	$	273,160	$	437,168	$	770,276	$	279,648	$	3,726,020	$	6,228,936

———

(1)Represents the contractual principal payment due dates for the Company’s long-term debt and does not reflect the reclassification of $159.3 million of long-term debt, net of unamortized deferred financing costs of $5.7 million, to current due to debt defaults that existed as of the date of the issuance of the financial statements (see above for additional details) as of December 31, 2019.

(2)Includes the $474.6 million Bridge Facility maturing on September 24, 2020. The Company has a one-year extension option and intends, through its subsidiaries, to complete a refinancing of the balance on a long-term basis prior to maturity. The balance, net of unamortized deferred financing costs, is included within non-current liabilities in the consolidated balance sheets.

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Segment Reporting - Revenue Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	$ 206,734	$ 253,808	$ 255,366	$ 225,332	$ 213,093	$ 246,042	$ 179,888	$ 127,547	$ 941,240	$ 766,570	$ 610,471
United States
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									457,718	473,950	519,551
Canada
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									43,672	41,174	44,636
Spain
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									338,669	186,655	0
Portugal
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									38,833	17,269	0
United Kingdom
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									1,639	1,597	15,002
URUGUAY
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									29,573	17,302	0
Chile
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues									$ 31,136	$ 28,623	$ 31,282

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Related Parties - SunEdison Matters (Details)				3 Months Ended	12 Months Ended
	Aug. 03, 2018 USD ($)	Aug. 31, 2017 USD ($)	Mar. 27, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) MW	Jul. 14, 2016 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
General and administrative expenses - affiliate					$ 28,070,000	$ 16,239,000	$ 13,391,000
Fee paid to related party					$ 0	$ 0	17,601,000
Insurance coverage								$ 150,000,000.0
Payments for insurance settlement			$ 32,000,000.0
Chamblee Class Action
Related Party Transaction [Line Items]
Litigation settlement, portion covered by insurance providers	$ 13,600,000	$ 13,600,000
O&M Services
Related Party Transaction [Line Items]
Fee paid to related party							17,600,000
Asset Management Services
Related Party Transaction [Line Items]
Fee paid to related party							26,700,000
SunEdison
Related Party Transaction [Line Items]
General and administrative expenses - affiliate							$ 4,500,000
Proceeds from warranty claims				$ 7,000,000.0
SunEdison | Management Services Agreement
Related Party Transaction [Line Items]
Base management fee percentage									250.00%
Management fee due to SunEdison in 2017 not to exceed									$ 9,000,000.0
SunEdison | Transition Services Agreements
Related Party Transaction [Line Items]
Capacity of power (MW) | MW							101.6
Termination noticed required							10 days
SunEdison | Chile Facility EPC Contract
Related Party Transaction [Line Items]
Proceeds from warranty claims				$ 4,800,000

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Other Non-Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Other Liabilities [Abstract]

Schedule of Other Current Assets

Other current assets presented in the consolidated balance sheets consisted of the following:

	As of December 31,
(In thousands)	2019		2018
Taxes receivable	$	14,435	$	18,798
Indemnity receivable	15,229		15,348
Spare parts inventory	266		7,562
Purchased solar renewable energy credits	5,019		—
Due from financial institutions	6,299		—
Due from service provider	8,212		—
Note receivable from public utility company	4,187		1,027
Miscellaneous	4,035		9,298
Total other current assets	$	57,682	$	52,033

Other Non-Current Liabilities

Other liabilities presented in the consolidated balance sheets consisted of the following:

	As of December 31,
(In thousands)	2019		2018
Energy tracking accounts payable	$	71,277	$	38,993
Intangible liabilities	15,864		18,883
Deferred revenue	9,388		12,090
Due to service provider	4,484		4,587
Miscellaneous	11,059		16,235
Total other non-current liabilities	$	112,072	$	90,788

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Quarterly Financial Information (Unaudited) (Details) $ / shares in Units, shares in Thousands		3 Months Ended								12 Months Ended
	Dec. 20, 2019 USD ($) business MW	Dec. 31, 2019 USD ($) $ / shares shares	Sep. 30, 2019 USD ($) $ / shares shares	Jun. 30, 2019 USD ($) $ / shares shares	Mar. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares	Sep. 30, 2018 USD ($) $ / shares shares	Jun. 30, 2018 USD ($) $ / shares shares	Mar. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) $ / shares shares	Sep. 26, 2019 MW	Jul. 02, 2018	Jun. 12, 2018 MW	Feb. 07, 2018 MW	Sep. 30, 2017 MW
Condensed Financial Statements, Captions [Line Items]
Operating revenues, net		$ 206,734,000	$ 253,808,000	$ 255,366,000	$ 225,332,000	$ 213,093,000	$ 246,042,000	$ 179,888,000	$ 127,547,000	$ 941,240,000	$ 766,570,000	$ 610,471,000
Operating income (loss)		(10,967,000)	40,365,000	54,928,000	29,104,000	8,063,000	56,666,000	27,299,000	(22,049,000)	113,430,000	69,979,000	40,723,000
Interest expense, net		51,421,000	89,393,000	71,041,000	86,287,000	72,349,000	72,416,000	50,892,000	53,554,000	298,142,000	249,211,000	262,003,000
Net loss		(91,388,000)	(62,313,000)	(16,827,000)	(36,057,000)	(30,351,000)	(19,051,000)	(27,612,000)	(76,313,000)	(206,585,000)	(153,327,000)	(236,303,000)
Net income (loss) attributable to Class A common stockholders		$ (81,625,000)	$ (54,837,000)	$ (3,595,000)	$ (8,627,000)	$ (15,489,000)	$ (33,590,000)	$ (21,337,000)	$ 82,796,000	$ (148,684,000)	$ 12,380,000	$ (160,154,000)
Weighted-average basic and diluted Class A shares outstanding (in shares) | shares		217,608	209,155	209,142	209,142					213,275	182,239	103,866
Weighted average Class A common shares outstanding - basic (in shares) | shares						209,142	209,142	161,568	148,139
Weighted average Class A common shares outstanding - diluted (in shares) | shares						209,142	209,142	161,568	148,166
Net (loss) earnings per weighted average Class A common share - basic and diluted (usd per share) | $ / shares		$ (0.38)	$ (0.26)	$ (0.02)	$ (0.04)	$ (0.07)	$ (0.16)	$ (0.13)	$ 0.56	$ (0.70)	$ 0.07	$ (1.61)
Accretion expense										$ 15,475,000	$ 6,866,000	$ 8,578,000
Loss on modification and extinguishment of debt, net		$ 31,100,000								26,953,000	1,480,000	81,099,000
Gain on sale of renewable energy facilities										2,252,000	0	37,116,000
Impairment of renewable energy facilities										0	15,240,000	1,429,000
Reduction in noncontrolling interest											151,200,000
Adjustment related to change in accretion period			$ (500,000)	$ (500,000)						27,917,000	(15,734,000)	$ 0
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Condensed Financial Statements, Captions [Line Items]
Capacity of power (MW) | MW																	0.3
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Distributed Generation Facilities
Condensed Financial Statements, Captions [Line Items]
Capacity of power (MW) | MW	6.0
Gain on sale of renewable energy facilities	$ 2,300,000	2,300,000
Number of assets sold | business	6
Commodity contracts - power
Condensed Financial Statements, Captions [Line Items]
Change in fair value of commodity contracts						$ (5,300,000)	$ 900,000	$ 10,800,000
Correction for Overstatement of Taxable Income
Condensed Financial Statements, Captions [Line Items]
Reduction in noncontrolling interest									$ 151,200,000
REC Sales Agreement
Condensed Financial Statements, Captions [Line Items]
Impairment of renewable energy facilities									$ 15,200,000		15,200,000
Solar Segment
Condensed Financial Statements, Captions [Line Items]
Operating revenues, net										316,433,000	298,966,000
Impairment of renewable energy facilities											15,200,000
Wind
Condensed Financial Statements, Captions [Line Items]
Operating revenues, net										$ 286,139,000	280,949,000
WGL Acquisition
Condensed Financial Statements, Captions [Line Items]
Operating revenues, net		13,773,000
Operating income (loss)		166,000
Net loss		80,000
Capacity of power (MW) | MW													320
Saeta Yield
Condensed Financial Statements, Captions [Line Items]
Operating revenues, net						88,642,000	107,903,000	24,681,000
Operating income (loss)						21,824,000	37,212,000	10,055,000
Interest expense, net						14,405,000	13,241,000	(4,114,000)
Net loss						4,819,000	$ 21,850,000	$ 11,545,000
Voting interests acquired															95.28%	100.00%
Remaining voting interest to be acquired														4.72%	4.72%
Saeta Yield | Regulated Solar and Wind
Condensed Financial Statements, Captions [Line Items]
Capacity of power (MW) | MW															1,000	1,000
Saeta Yield | Solar Segment
Condensed Financial Statements, Captions [Line Items]
Capacity of power (MW) | MW															250	778
Saeta Yield | Wind
Condensed Financial Statements, Captions [Line Items]
Capacity of power (MW) | MW															778	250
Scenario, Adjustment
Condensed Financial Statements, Captions [Line Items]
Accretion expense			3,300,000
Depreciation		$ 3,700,000	$ 3,700,000
Adjustment related to change in accretion period						(6,300,000)					$ (15,700,000)
Adjustment to reduce previously reported accretion related to prior periods						$ (4,400,000)

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Nature of Operations and Organization (Details)						12 Months Ended
	Mar. 16, 2020	Jun. 12, 2018	Jun. 11, 2018	Oct. 16, 2017 shares	Oct. 15, 2017 shares	Dec. 31, 2018 shares	Mar. 17, 2020	Jan. 11, 2020	Dec. 31, 2019 shares	Dec. 31, 2017 shares
Business Acquisition [Line Items]
Common stock outstanding (in shares)						209,142,000			226,501,000	148,086,000
Treasury stock (in shares)						500,420			1,051,298
Share Purchase Agreement
Business Acquisition [Line Items]
Percentage of ownership after transaction			65.00%
Class A Common Stock Issued
Business Acquisition [Line Items]
Common stock outstanding (in shares)				148,086,027
Treasury stock (in shares)				138,402
Class A Common Stock Issued | SunEdison
Business Acquisition [Line Items]
Exchanged (in shares)				48,202,310	48,202,310
Equity held				36.90%	36.90%
Affiliates of Brookfield | TerraForm Power
Business Acquisition [Line Items]
Ownership percentage of Terra									62.00%
Affiliates of Brookfield | TerraForm Power | Share Purchase Agreement
Business Acquisition [Line Items]
Percentage of ownership after transaction		65.00%				65.00%
Brookfield Renewable | Subsequent Event | Common Stock | TerraForm Power | Class A Common Stock Issued
Business Acquisition [Line Items]
Proposal to acquire shares of Common Stock for consideration of shares equivalent	0.381
Brookfield Renewable | TerraForm Power | Subsequent Event
Business Acquisition [Line Items]
Ownership percentage by other entities							30.00%	30.00%
Orion US Holdings 1 LP | TerraForm Power
Business Acquisition [Line Items]
Ownership percentage of Terra				51.00%
Brookfield Asset Management
Business Acquisition [Line Items]
Voting interests acquired				51.00%

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(Loss) Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Schedule of (Loss) Earnings Per Share, Basic and Diluted

Basic and diluted (loss) earnings per share of the Company’s Common Stock for the years ended December 31, 2019,

2018 and 2017 was calculated as follows:

	Year Ended December 31,
(In thousands, except per share amounts)	2019		2018		2017
Basic and diluted (loss) earnings per share:
Net (loss) income attributable to Class A common stockholders	$	(148,684)	$	12,380	$	(160,154)
Less: accretion of redeemable non-controlling interest	—		—		(6,729)
Less: cash distributions to Class A shares and participating RSAs	—		—		(285,497)
Undistributed income (loss) attributable to Class A shares	(148,684)		12,380		(452,380)
Weighted average basic and diluted Class A shares outstanding1	213,275		182,239		103,866
Distributed earnings per share	—		—		2.75
Undistributed (loss) earnings per share	(0.70)		0.07		(4.36)
Basic and diluted (loss) earnings per share	$	(0.70)	$	0.07	$	(1.61)

———

(1)The computation of diluted earnings per share of the Company’s Common Stock for the year ended December 31, 2019, excluded the impact of 191,936 potentially dilutive unvested RSUs outstanding at December 31, 2019, because the effect would have been anti-dilutive.

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Commitments And Contingencies (Details) $ in Millions					1 Months Ended		12 Months Ended
	Dec. 09, 2019 claim	Nov. 01, 2019	Aug. 10, 2018 GW	May 27, 2016 USD ($) business	Jun. 30, 2019 claim	Jan. 31, 2019 USD ($)	Dec. 31, 2019 USD ($) plaintiff	Dec. 31, 2018 USD ($)
Loss Contingencies [Line Items]
Outstanding letters of credit							$ 266.9	$ 197.7
Domenech Zornoza v. TerraForm Global, Inc. et. al
Loss Contingencies [Line Items]
Number of claims dismissed | claim	2
Number of claims | claim	3
Chile Project Arbitration | Judicial Ruling
Loss Contingencies [Line Items]
Number of claims dismissed | claim					2
SunEdison | FirstWind Purchase Agreement
Loss Contingencies [Line Items]
Settlement				$ 231.0
Number of resignations | business				2
Litigation settlement interest, percentage				9.00%
Project Level Subsidiaries | Court of Federal Claims
Loss Contingencies [Line Items]
Number of plaintiffs | plaintiff							2
Damages awarded						$ 10.0
Framework Agreement | General Electric
Loss Contingencies [Line Items]
Framework agreement period			11 years
Nameplate capacity (MW) | GW			1.6
Framework Agreement | SMA Solar Technology
Loss Contingencies [Line Items]
Framework agreement period		10 years
Revolving Credit Facility | Line of Credit
Loss Contingencies [Line Items]
Outstanding letters of credit							$ 115.5	$ 99.5

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Related Parties - Amended and Restated Terra LLC Agreement (Details) - Incentive Distribution Rights - Brookfield Asset Management	Dec. 31, 2019 $ / shares
Related Party Transaction [Line Items]
Quarterly distribution rights, level one (usd per share)	$ 0.93
Quarterly distribution rights, level two (usd per share)	$ 1.05
Quarterly distribution rights, level one, percentage	15.00%
Quarterly distribution rights, level two, percentage	85.00%
Quarterly distribution rights, level three (usd per share)	$ 0.12
Quarterly distribution rights, level three, percentage	75.00%
Quarterly distribution rights, level four, percentage	25.00%

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Schedule of Share-based Compensation, Restricted Stock Award Activity

The following table presents information regarding outstanding RSAs as of December 31, 2019, 2018 and 2017. and changes during the year then ended:

	Number of RSAs Outstanding	Weighted-Average Grant-Date Fair Value Per Share		Aggregate Intrinsic Value (in millions)
Balance at January 1, 2017	366,195	$	8.51
Vested	(366,195)	8.51
Balance as of December 31, 2017, 2018 and 2019	—	—		$	—

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity

Restricted Stock Units

The RSUs do not entitle the holders to voting rights and holders of the RSUs do not have any right to receive cash distributions. The following table presents information regarding outstanding RSUs as of December 31, 2019 and 2018 and changes during the year then ended:

(In thousands, except per share data and the number of years)	Number of RSUs Outstanding	Weighted- Average Exercise Price		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Life
Balance at January 1, 2017	1,622,953
Granted	523,877
Vested	(1,414,857)
Forfeited	(731,973)
Balance as of December 31, 2017	—
Granted	117,424
Forfeited	(14,124)
Balance as of December 31, 2018	103,300	$	11.15	$	1,159	2 years
Granted	156,550	12.17
Vested	(20,878)	11.15
Forfeited	(47,036)	11.64
Balance as of December 31, 2019	191,936	11.57		2,954		1 year

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Fair Value of Financial Instruments - Changes in Fair Value of Derivative Classified as Level 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	$ 79,652	$ 80,268
Realized and unrealized (losses) gains:
Included in other comprehensive loss	(8,920)	(4,736)
Included in operating revenues, net	(12,441)	6,244
Net settlements	1,021	(2,124)
Balance as of December 31	$ 59,312	$ 79,652

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Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Cash and Cash Equivalents [Line Items]
Non-current restricted cash reclassified to current	$ 11.0	$ 11.2
Project Level Subsidiaries
Cash and Cash Equivalents [Line Items]
Cash	$ 138.5	$ 177.6

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Derivatives - Schedule of Notional Amounts (Details) € in Thousands, MWh in Thousands, $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) MWh	Dec. 31, 2018 USD ($) MWh	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 EUR (€)	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 EUR (€)
Interest rate swaps | Derivatives Designated as Hedging Instruments
Derivative [Line Items]
Notional amount	$ 441,628	$ 357,797	$ 138,575	€ 310,721	$ 147,522	€ 0
Interest rate swaps | Derivatives not designated as hedges
Derivative [Line Items]
Notional amount	$ 11,399	$ 12,326		745,719		1,044,253
Commodity contracts - power | Derivatives Designated as Hedging Instruments
Derivative [Line Items]
Nonmonetary notional amount (MWhs) | MWh	5,360	6,030
Commodity contracts - power | Derivatives not designated as hedges
Derivative [Line Items]
Nonmonetary notional amount (MWhs) | MWh	7,610	8,707
Foreign Currency Contracts | Derivatives Designated as Hedging Instruments
Derivative [Line Items]
Notional amount			$ 94,000	199,750	$ 81,600	320,000
Foreign Currency Contracts | Derivatives not designated as hedges
Derivative [Line Items]
Notional amount | €				118,550		640,200
Foreign Exchange Option | Derivatives not designated as hedges
Derivative [Line Items]
Notional amount | €				€ 625,200		€ 0

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Leases - Balance Sheet Information (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Operating leases:
Right-of-use asset	$ 288,321
Accounts payable, accrued expenses and other current liabilities	18,138
Operating lease obligations, less current portion	272,894
Total operating lease liabilities	$ 291,032
Weighted Average Remaining Lease Term:
Operating leases	17 years 7 months 6 days
Weighted Average Discount Rate:
Operating leases	4.80%

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Oct. 16, 2017	Oct. 15, 2017
Income Taxes [Line Items]
Adjustment to valuation allowance	$ (20.1)
Domestic Tax Authority
Income Taxes [Line Items]
Operating loss carryforwards		$ 2,290.0
Net operating loss carryforwards expected to expire before use		560.0
Net operating loss carryforward, not limited		1,730.0
Foreign Tax Authority
Income Taxes [Line Items]
Operating loss carryforwards		$ 132.1
Terra LLC | TerraForm Power
Income Taxes [Line Items]
Ownership percentage of Terra				66.00%
Voting interests acquired			100.00%
Terra LLC | SunEdison
Income Taxes [Line Items]
Ownership percentage by other entities				34.00%

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Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Oct. 16, 2019	Dec. 31, 2018	Dec. 12, 2017	Jul. 17, 2015
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 6,288,469		$ 5,796,936
Financing lease obligations	59,533
Unamortized discounts and premiums, net	(3,509)		(15,913)
Deferred financing costs, net	(49,578)		(19,178)
Less current portion of long-term debt and financing lease obligations	(441,951)		(464,332)
Long-term debt and financing lease obligations, less current portion	$ 5,793,431		5,297,513
Weighted average interest rate	4.38%
Interest rate	5.80%
Secured Debt
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 3,854,386		3,496,370
Weighted average interest rate	4.38%
Fixed interest rate, of balance	3800.00%
Variable interest rate, of balance	6200.00%
Bridge Facility
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 474,550		0
Variable/Blended/Imputed interest rate	291.00%
Capital Lease Obligations
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations			77,066
Senior Notes due 2023 | Secured Debt
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 500,000		500,000
Fixed interest rate	425.00%			4.25%
Senior Notes due 2025 | Secured Debt
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 0		300,000
Fixed interest rate					612.50%
Senior Notes due 2028 | Secured Debt
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 700,000		700,000
Fixed interest rate	500.00%			5.00%
Senior Notes due 2030 | Secured Debt
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 700,000		0
Fixed interest rate	475.00%	4.75%
Revolver | Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 0		377,000
Term Loan | Secured Debt
Debt Instrument [Line Items]
Total principal due for long-term debt and financing lease obligations	$ 0		$ 346,500

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Intangible Assets, Net And Goodwill - Intangibles Gross Carrying Amount Accumulated Amortization and Net Book Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Licensing agreements
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	$ 765,451	$ 1,015,824
Accumulated Amortization	(81,647)	(36,374)
Net Book Value	$ 683,804	$ 979,450
Licensing agreements | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period	13 years	15 years
Favorable rate revenue contracts
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	$ 745,784	$ 738,488
Accumulated Amortization	(195,287)	(166,507)
Net Book Value	$ 550,497	$ 571,981
Favorable rate revenue contracts | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period	12 years	14 years
In-place value of market rate revenue contracts
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	$ 688,832	$ 532,844
Accumulated Amortization	(129,841)	(100,543)
Net Book Value	$ 558,991	$ 432,301
In-place value of market rate revenue contracts | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period	16 years	18 years
Favorable rate land leases
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		$ 15,800
Accumulated Amortization		(3,128)
Net Book Value		$ 12,672
Favorable rate land leases | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period		16 years
Total Favorable Rate Leases and Other
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	$ 2,200,067	$ 2,302,956
Accumulated Amortization	(406,775)	(306,552)
Net Book Value	1,793,292	1,996,404
Unfavorable rate revenue contracts
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	48,420	58,508
Accumulated Amortization	(32,556)	(41,605)
Net Book Value	$ 15,864	$ 16,903
Unfavorable rate revenue contracts | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period	8 years	6 years
Unfavorable rate operations and maintenance contracts
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		$ 5,000
Accumulated Amortization		(3,802)
Net Book Value		$ 1,198
Unfavorable rate operations and maintenance contracts | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period		1 year
Unfavorable rate land lease
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		$ 1,000
Accumulated Amortization		(218)
Net Book Value		$ 782
Unfavorable rate land lease | Weighted average
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Weighted Average Amortization Period		14 years
Total Unfavorable Rate Lease
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount	$ 48,420	$ 64,508
Accumulated Amortization	(32,556)	(45,625)
Net Book Value	$ 15,864	$ 18,883

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Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

LEASES

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment.

The components of lease expense were as follows:

(In thousands)	Year Ended December 31, 2019
Fixed operating lease cost	$	21,619
Variable operating lease cost1	5,884
Total operating lease cost	$	27,503

———

(1)Primarily related to production-based variable inputs and adjustments for inflation.

Supplemental cash flow information related to the Company’s leases was as follows:

(In thousands)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases1	$	16,485

———

(1)Right-of-use assets, excluding the effect of acquisitions, obtained in exchange for lease obligations during the year ended December 31, 2019, were not material.

Supplemental balance sheet information related to the Company’s leases was as follows:

(In thousands, except lease term and discount rate)	As of December 31, 2019
Operating leases:
Right-of-use assets	$	288,321
Accounts payable, accrued expenses and other current liabilities	18,138
Operating lease obligations, less current portion	272,894
Total operating lease liabilities	$	291,032
Weighted Average Remaining Lease Term:
Operating leases	17.6
Weighted Average Discount Rate:
Operating leases	4.8		%

The maturities of the Company’s operating lease liabilities by fiscal year were as follows:

(In thousands)
2020	$	21,921
2021	21,828
2022	22,046
2023	22,220
2024	22,424
Thereafter	319,532
Total lease payments	429,971
Less: Imputed interest	(138,939)
Total	$	291,032

The following table summarizes the Company’s future commitments under operating leases as of December 31, 2018:

(In thousands)	2019		2020		2021		2022		2023		Thereafter		Total
Rent	$	20,002	$	20,005	$	20,241	$	20,410	$	20,577	$	331,425	$	432,660

The operating revenues from delivering electricity and the related products from owned solar and wind renewable energy facilities under PPAs in which the Company is the lessor, the majority of which is variable in nature, is recognized when electricity is delivered and is accounted for as rental income under the lease standard. The Company determines if an arrangement is a lease at contract inception, and if so, includes both lease and non-lease components as a single component and accounts for it as a lease. The Company’s PPAs do not contain any residual value guarantees or material restrictive covenants. The Company manages its risk associated with the residual value of its leased assets by retaining the ability to sell RECs through REC sale agreements. As a result of the adoption ASC 842 on January 1, 2019, the Company does not expect the future PPAs that it will enter into to meet the definition of a lease. See Note 2. Summary of Significant Accounting Policies for additional details.

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Revenue

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

The following table presents the Company’s operating revenues, net and disaggregated by revenue source:

	Year Ended December 31, 2019								Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Total		Solar		Wind		Regulated Solar and Wind		Total
PPA rental income	$	199,266	$	191,508	$	—	$	390,774	$	198,610	$	192,324	$	—	$	390,934
Commodity derivatives	—		37,054		—		37,054		—		46,287		—		46,287
PPA and market energy revenue	46,740		79,253		97,953		223,946		39,566		54,998		58,742		153,306
Capacity revenue from remuneration programs1	—		—		204,991		204,991		—		—		108,242		108,242
Amortization of favorable and unfavorable rate revenue contracts, net	(8,850)		(31,090)		—		(39,940)		(9,743)		(29,024)		—		(38,767)
Energy revenue	237,156		276,725		302,944		816,825		228,433		264,585		166,984		660,002
Incentive revenue2	79,277		9,414		35,724		124,415		70,533		16,364		19,671		106,568
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	941,240	$	298,966	$	280,949	$	186,655	$	766,570

———

(1)Represents the return related to the Company’s investments associated with its renewable energy facilities in Spain. See Note 2. Summary of Significant Accounting Policies for additional details.

(2)Incentive revenue earned at the Regulated Solar and Wind segment represents the return per MWh generated by the Company’s solar facilities in Spain to recover certain operating expenses. See Note 2. Summary of Significant Accounting Policies for additional details.

Contract balances and performance obligations

The Company recognizes accounts receivable when its right to consideration from the performance of services becomes unconditional. The Company establishes an allowance for doubtful accounts to adjust its receivables to amounts considered to be ultimately collectible and charges to the allowance are recorded within general and administrative expenses in the consolidated statements of operations. The Company’s allowance is based on a variety of factors, including the length of time receivables are past due, significant one-time events, the financial health of its customers and historical experience. As of December 31, 2019 and 2018, the Company’s receivable balances related to PPA contracts with solar and wind customers were approximately $104.1 million and $83.5 million, respectively. Trade receivables for PPA contracts are reflected within accounts receivable, net in the consolidated balance sheets. The Company typically receives payment within 30 days for invoiced PPA revenue.

Energy revenues yet to be earned under these contracts are expected to be recognized between 2020 and 2043. The Company applies the practical expedient in Topic 606 to its bundled PPA contract arrangements, and accordingly, does not disclose the value of unsatisfied performance obligations for contracts for which it recognizes revenue at the amount to which it has the right to invoice for services performed.

As of December 31, 2019 and December 31, 2018, other liabilities in the consolidated balance sheets included deferred revenue comprising of $8.4 million and $8.8 million upfront government incentives, respectively, and $1.8 million and $4.9 million contract liabilities related to performance obligations that have not yet been satisfied, respectively. These contract liabilities represented advanced customer receipts primarily related to future REC deliveries that are recognized into revenue under Topic 606. The amount of revenue recognized during the year ended December 31, 2019 and 2018, related to contract liabilities was $3.1 million and $1.3 million, respectively.

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Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Operating revenues, net	$ 941,240,000	$ 766,570,000	$ 610,471,000
Operating costs and expenses:
Cost of operations	279,896,000	220,907,000	150,733,000
Cost of operations - affiliate	0	0	17,601,000
General and administrative expenses	81,063,000	87,722,000	139,874,000
General and administrative expenses - affiliate	28,070,000	16,239,000	13,391,000
Acquisition costs	3,751,000	7,721,000	0
Acquisition costs - affiliate	920,000	6,925,000	0
Impairment of renewable energy facilities	0	15,240,000	1,429,000
Depreciation, accretion and amortization expense	434,110,000	341,837,000	246,720,000
Total operating costs and expenses	827,810,000	696,591,000	569,748,000
Operating income (loss)	113,430,000	69,979,000	40,723,000
Other expenses (income):
Interest expense, net	298,142,000	249,211,000	262,003,000
Loss on modification and extinguishment of debt, net	26,953,000	1,480,000	81,099,000
Gain on foreign currency exchange, net	(12,726,000)	(10,993,000)	(6,061,000)
Gain on sale of renewable energy facilities	(2,252,000)	0	(37,116,000)
Other income, net	(2,000,000)	(4,102,000)	(3,258,000)
Total other expenses, net	308,117,000	235,596,000	296,667,000
Loss before income tax expense (benefit)	(194,687,000)	(165,617,000)	(255,944,000)
Income tax expense (benefit)	11,898,000	(12,290,000)	(19,641,000)
Net income (loss)	(206,585,000)	(153,327,000)	(236,303,000)
Less: Net (loss) income attributable to redeemable non-controlling interests	(11,983,000)	9,209,000	1,596,000
Less: Net loss attributable to non-controlling interests	(45,918,000)	(174,916,000)	(77,745,000)
Net (loss) income attributable to Class A common stockholders	$ (148,684,000)	$ 12,380,000	$ (160,154,000)
Weighted average number of shares:
Class A common stock - Basic and diluted (in shares)	213,275	182,239	103,866
(Loss) earnings per share:
Class A common share - Basic and diluted (usd per share)	$ (0.70)	$ 0.07	$ (1.61)
Distribution declared per share:
Class A common stock (usd per share)	$ 0.8056	$ 0.7600	$ 1.9400

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Segment Reporting

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segment Reporting

SEGMENT REPORTINGThe Company has three reportable segments: Solar, Wind, and Regulated Solar and Wind. These segments, which represent the Company’s entire portfolio of renewable energy facilities, have been determined based on the management approach. The management approach designates the internal reporting used by management for making decisions and assessing performance as the source of the reportable segments. Each of the Company’s reportable segments represents an aggregation of operating segments. An operating segment is defined as a component of an enterprise that engages in business activities from which it may earn revenues and incur expenses, and that has discrete financial information that is regularly reviewed by the chief operating decision maker (“CODM”) in deciding how to allocate resources. The Company’s Chief Executive Officer and Chief Financial Officer have been identified as the CODMs. The Company’s operating segments consist of: (i) Distributed Generation, North America Solar Utility, International Solar Utility, which are aggregated into the Solar reportable segment; (ii) Northeast Wind, Central Wind, Texas Wind, Hawaii Wind and International Wind operating segments, which are aggregated into the Wind reportable segment; and (iii) the Spanish Regulated Solar and Spanish Regulated Wind operating segments that are aggregated within the Regulated Solar and Wind reportable segment. The International Wind, comprising the Company’s wind operations in Portugal and Uruguay, and the Spanish Regulated Solar and Wind operating segments were added during the second quarter of 2018 upon the acquisition of Saeta and represent its entire operations. See Note 3. Acquisitions and Divestitures for additional details. The operating segments were aggregated as they have similar economic characteristics and meet the aggregation criteria per ASC 280. The CODMs evaluate the performance of the Company’s operating segments principally based on operating income or loss. Corporate expenses include general and administrative expenses, acquisition costs, interest expense on corporate-level indebtedness, stock-based compensation and depreciation expense. All net operating revenues for the years ended December 31, 2019, 2018, and 2017, were earned by the Company’s reportable segments from external customers in the United States (including Puerto Rico), Canada, Spain, Portugal, the United Kingdom, Uruguay and Chile, as applicable.

The following table reflects summarized financial information for the Company’s reportable segments for the years ended December 31, 2019, 2018 and 2017:

	Year Ended December 31, 2019
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	—	$	941,240
Depreciation, accretion and amortization expense	118,564		175,842		138,213		1,491		434,110
Other operating costs and expenses	66,334		142,031		90,516		94,819		393,700
Operating income (loss)	131,535		(31,734)		109,939		(96,310)		113,430
Interest expense, net	68,441		58,105		54,727		116,869		298,142
Other non-operating (income) expenses, net	(7,893)		(455)		3,994		14,329		9,975
Income tax expense (benefit)	2,309		193		1,326		8,070		11,898
Net income (loss)	$	68,678	$	(89,577)	$	49,892	$	(235,578)	$	(206,585)
Cash Flows
Capital expenditures	$	2,223	$	15,426	$	599	$	2,936	$	21,184
Balance Sheet
Total assets1	3,509,076		3,716,447		2,731,892		101,221		10,058,636

	Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	298,966	$	280,949	$	186,655	$	—	$	766,570
Depreciation, accretion and amortization expense	109,809		151,472		79,026		1,530		341,837
Impairment of renewable energy facilities	15,240		—		—		—		15,240
Other operating costs and expenses	74,778		123,203		46,289		95,244		339,514
Operating income (loss)	99,139		6,274		61,340		(96,774)		69,979
Interest expense, net	63,571		50,712		15,510		119,418		249,211
Other non-operating income, net	(4,248)		(108)		(2,261)		(6,998)		(13,615)
Income tax (benefit) expense	(20,346)		79		10,558		(2,581)		(12,290)
Net income (loss)	$	60,162	$	(44,409)	$	37,533	$	(206,613)	$	(153,327)
Cash Flows
Capital expenditures	$	4,325	$	12,219	$	—	$	5,901	$	22,445
Balance Sheet
Total assets1	2,762,977		3,733,049		2,748,126		86,202		9,330,354

	Year Ended December 31, 2017
(In thousands)	Solar		Wind		Corporate		Total
Operating revenues, net	$	337,233	$	273,238	$	—	$	610,471
Depreciation, accretion and amortization expense	108,695		135,785		2,240		246,720
Impairment of renewable energy facilities	1,429		—		—		1,429
Other operating costs and expenses	65,213		105,817		150,569		321,599
Operating income (loss)	161,896		31,636		(152,809)		40,723
Interest expense, net	70,439		77,398		114,166		262,003
Other non-operating (income) expenses, net	(36,399)		3,650		67,413		34,664
Income tax benefit	—		—		(19,641)		(19,641)
Net income (loss)	$	127,856	$	(49,412)	$	(314,747)	$	(236,303)
Cash Flows
Capital expenditures	$	302	$	7,670	$	420	$	8,392
Balance Sheet
Total assets1	2,897,036		3,400,858		89,127		6,387,021

———

(1)As of December 31, 2019, 2018 and 2017, respectively.

Operating Revenues, Net

The following table reflects operating revenues, net earned during the years ended December 31, 2019, 2018 and 2017, by geographic location:

	Year Ended December 31,
(In thousands)	2019		2018		2017
United States	$	457,718	$	473,950	$	519,551
Canada	43,672		41,174		44,636
Spain	338,669		186,655		—
Portugal	38,833		17,269		—
United Kingdom	1,639		1,597		15,002
Uruguay	29,573		17,302		—
Chile	31,136		28,623		31,282
Total operating revenues, net	$	941,240	$	766,570	$	610,471

Long-lived Assets, Net

Long-lived assets, net consist of renewable energy facilities, intangible assets, and goodwill as of December 31, 2019 and 2018. The following table is a summary of long-lived assets, net by geographic area:

	As of December 31,
(In thousands)	2019		2018
United States (including Puerto Rico)	$	5,722,092	$	5,030,483
Canada	366,862		362,829
Spain	2,574,546		2,503,420
Portugal	229,629		251,053
United Kingdom	17,289		13,183
Uruguay	261,189		264,798
Chile	155,098		161,217
Total long-lived assets, net	9,326,705		8,586,983
Current assets	553,347		501,185
Other non-current assets	178,584		242,186
Total assets	$	10,058,636	$	9,330,354

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements represent the results of TerraForm Power, which consolidates Terra LLC through its controlling interest.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated.

The Company elected not to push-down the application of the acquisition method of accounting to its consolidated financial statements following the consummation of the Merger and the change of control that occurred, as discussed in Note 1. Nature of Operations and Organization.

Principles of Consolidation

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements represent the results of TerraForm Power, which consolidates Terra LLC through its controlling interest.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated.

The Company elected not to push-down the application of the acquisition method of accounting to its consolidated financial statements following the consummation of the Merger and the change of control that occurred, as discussed in Note 1. Nature of Operations and Organization.

Reclassifications

Reclassifications

Certain prior period amounts that existed within the consolidated balance sheets as of December 31, 2018, have been reclassified to conform to the current period presentation. Specifically, the Company presented the balances of current and non-current derivative assets and liabilities, and prepaid expenses separately on the consolidated balance sheets. Additionally, the

Company presented the balances of current and non-current deferred revenue as components of current and non-current other liabilities, as appropriate.

Use of Estimates

Use of Estimates

In preparing the consolidated financial statements, the Company uses estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements. Such estimates also affect the reported amounts of revenues, expenses, and cash flows during the reporting period. To the extent there are material differences between the estimates and actual results, the Company’s future results of operations would be affected.

Cash and Cash Equivalents and Restricted Cash

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and money market funds with original maturity periods of three months or less when purchased.

Restricted Cash

Restricted cash consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements and funds held within the Company’s project companies that are restricted for current debt service payments and other purposes in accordance with the applicable debt agreements. These restrictions include: (i) cash on deposit in collateral accounts, debt service reserve accounts and maintenance reserve accounts; and (ii) cash on deposit in operating accounts but subject to distribution restrictions related to debt defaults existing as of the date of the balance sheet. Restricted cash that is not expected to become unrestricted within twelve months from the date of the balance sheet is presented within non-current assets in the consolidated balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful AccountsAccounts receivable are reported on the consolidated balance sheets, including both billed and unbilled amounts, and are adjusted for the allowance for doubtful accounts and any write-offs. The Company establishes an allowance for doubtful accounts to adjust its receivables to amounts considered to be ultimately collectible, and charges to the allowance are recorded within general and administrative expenses or cost of operations, as appropriate, in the consolidated statements of operations. The Company’s allowance for doubtful accounts is based on a variety of factors, including the length of time receivables are past due, significant one-time events, the financial health of its customers, and historical experience.

Renewable Energy Facilities

Renewable Energy Facilities

Renewable energy facilities consist of solar generation and storage facilities and wind power plants that are stated at cost. Expenditures for major additions and improvements are capitalized, and minor replacements, maintenance, and repairs are charged to expense as incurred. Depreciation of the Company’s solar and storage facilities is recognized using the straight-line composite method over their estimated useful lives which ranged from 12 to 28 years and 23 to 30 years, as of December 31, 2019 and 2018, respectively. Under this method, the Company’s assets with similar characteristics and estimated useful lives are grouped and depreciated as a single unit. Depreciation of the Company’s wind power plant is calculated based on the major components of wind power plants and is recognized over the estimated periods during which these major components remain in service. The Company’s major components of wind power plants had remaining useful lives ranging from 8 to 36 years. As of December 31, 2019 and 2018, they had a weighted average remaining useful life of 19 and 21 years, respectively.

Construction in-progress represents the cumulative construction costs, including the costs incurred for the purchase of major equipment and engineering costs and any capitalized interest. Once the project achieves commercial operation, the Company reclassifies the amounts recorded in construction in progress to renewable energy facilities in service.

Finite-Lived Intangibles

Finite-Lived IntangiblesThe Company’s finite-lived intangible assets and liabilities represent revenue contracts, consisting of long-term licensing agreements, power purchase contracts (“PPAs”), and renewable energy credits (“RECs”) that were obtained through third-party acquisitions. The revenue contract intangibles comprise favorable and unfavorable rate PPAs and REC agreements and the in-place value of market-rate PPAs. Intangible assets and liabilities that have determinable estimated lives are amortized on a straight-line basis over those estimated lives. Amortization of favorable and unfavorable rate revenue contracts is recorded within operating revenues, net in the consolidated statements of operations. Amortization expense related to the licensing contracts and in-place value of market-rate revenue contracts is recorded within depreciation, accretion and amortization expense in the consolidated statements of operations. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used up. The amounts and useful lives assigned to intangible assets acquired and liabilities assumed impact the amount and timing of future amortization.

Impairment of Renewable Energy Facilities and Intangibles

Impairment of Renewable Energy Facilities and Intangibles

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recognized when indicators of impairment are present and the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. The Company review our current activities, changes in the conditions of our renewable energy facilities and the market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a long-lived asset group, generally this is an individual renewable energy project, include a substantial and sustained decline in the trading price of our Common Stock, severe adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in forecasted operating revenues and earnings of our operating projects, and deterioration in the performance of our renewable energy facilities. An impairment charge is measured as the difference between a long lived asset group’s carrying amount and its fair value. The fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets, and present value techniques.

Goodwill

Goodwill

The Company evaluates goodwill for impairment at least annually on December 1. The Company performs an impairment test between scheduled annual tests if facts and circumstances indicate that it is more-likely-than-not that the fair value of a reporting unit that has goodwill is less than its carrying value. A reporting unit is either the operating segment level or one level below, which is referred to as a component. The level at which the impairment test is performed requires judgment as to whether the operations below the operating segment constitute a self-sustaining business or whether the operations are similar such that they should be aggregated for purposes of the impairment test. The Company defines its reporting units to be consistent with its operating segments.

The Company may first make a qualitative assessment of whether it is more-likely-than-not that a reporting unit’s fair value is less than its carrying value to determine whether it is necessary to perform the quantitative goodwill impairment test. The qualitative impairment test includes considering various factors, including macroeconomic conditions, industry and market conditions, cost factors, a sustained share price or market capitalization decrease, and any reporting unit specific events. If it is determined through the qualitative assessment that a reporting unit’s fair value is more-likely-than-not greater than its carrying value, the quantitative impairment test is not required. If the qualitative assessment indicates it is more-likely-than-not that a reporting unit’s fair value is not greater than its carrying value, the Company must perform the quantitative impairment test. The Company may also elect to proceed directly to the quantitative impairment test without considering such qualitative factors.

The quantitative impairment test is the comparison of the fair value of a reporting unit with its carrying amount, including goodwill. In accordance with the authoritative guidance over fair value measurements, the Company defines the fair value of a reporting unit as the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. The Company primarily uses the income approach methodology of valuation, which uses the discounted cash flow method to estimate the fair values of the Company’s reporting units. The Company does not believe that a cost approach is relevant to measuring the fair values of its reporting units.

Significant management judgment is required when estimating the fair value of the Company’s reporting units, including the forecasting of future operating results, the discount rates and expected future growth rates that it uses in the discounted cash flow method of valuation, and in the selection of comparable businesses that are used in the market approach. If the estimated fair value of the reporting unit exceeds the carrying value assigned to that unit, goodwill is not impaired. If the carrying value assigned to a reporting unit exceeds its estimated fair value, the Company records an impairment charge based on the excess of the reporting unit’s carrying amount over its fair value. The impairment charge is limited to the amount of goodwill allocated to the reporting unit.

The Company performed a qualitative impairment test for the goodwill balance of $128.0 million, and concluded that the carrying amount of the related reporting units does not exceed its fair value. No goodwill impairment charges were recorded for the years ended December 31, 2019, 2018 and 2017.

Finance Lease Obligations and Leases

Financing Lease Obligations

Certain of the Company’s assets were financed with sale-leaseback arrangements. Proceeds received from a sale-leaseback are treated using the financing method when the sale of the renewable energy facility is not recognizable. A sale is not recognized when the leaseback arrangements include a prohibited form of continuing involvement, such as an option or obligation to repurchase the assets under the Company’s master lease agreements. Under these arrangements, the Company does not recognize any profit until the sale is recognizable, which the Company expects to recognize at the end of the arrangement when the contract is canceled and the initial deposits received are forfeited by the financing party.

The Company is required to make rental payments throughout the leaseback arrangements. These payments are allocated between principal and interest payments using an effective yield method.

Leases

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which primarily changes the lessee’s accounting for operating leases by requiring the recognition of lease right-of-use assets and lease liabilities. The guidance also eliminates previous real estate specific provisions. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842), Targeted Improvements, which amended the standard to give entities another option to apply the requirements of the standard in the period of adoption (January 1, 2019) or Effective Date Method. The Company adopted the new accounting guidance on January 1, 2019 using a modified retrospective approach reflecting the Effective Date Method of adoption in which the Company continued to apply the guidance in ASC 840, Leases to the comparable periods presented in the year of adoption.

The Company made the following elections provided under the standard:

•The package of practical expedients that permits the Company to retain its existing lease assessment and classification;

•The practical expedient that allows the Company to not evaluate existing and expired land easements;

•The practical expedient to not separate non-lease components in power purchase agreements (“PPAs”) in which the Company is the lessor in providing energy, capacity, and incentive products for a bundled fixed rate; and

•The Company elected not to apply the recognition requirements for short-term operating leases, defined as a term of twelve months or shorter, from the commencement date.

The Company evaluated the impact of Topic 842 as it relates to operating leases for land, buildings and equipment for which it is the lessee and reviewed its existing contracts for embedded leases. The adoption of the new standard resulted in the recognition of right-of-use assets and lease liabilities of approximately $262.1 million and $256.0 million, respectively, as of January 1, 2019, for operating leases, whereas the Company’s accounting for finance leases remained substantially unchanged.

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment. Leases with an initial term of twelve months or shorter are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. During the year ended December 31, 2019, the Company did not have any leases with an initial term of less than twelve months.

Operating lease right-of-use assets are included within renewable energy facilities, net, whereas right-of-use liabilities are included within accounts payable, accrued expenses and other current liabilities. Right-of-use assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. As the Company’s leases do not provide an implicit rate, the Company calculated an incremental borrowing rate by leveraging external transactions at comparable entities and internally available information to determine the present value of lease payments. The Company’s leases have remaining lease terms ranging from 5 to 41 years.

        The Company’s lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise any such options. Lease expense is recognized on a straight-line basis over the expected lease term. Although some of the Company’s leases contain lease and non-lease components, the Company applies the practical expedient to account for each lease component and non-lease component as a single lease component. Lease payments include fixed rent and taxes, where applicable, and exclude variable rental payments that include other operating expenses is recognized as incurred. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive

covenants. The following tables outline the different components of operating leases and other terms and conditions of the lease agreements where the Company is the lessee.

As discussed above, a significant portion of the Company’s operating revenues are generated from delivering electricity and related products from owned solar and wind renewable energy facilities under PPAs in which the Company is the lessor. Revenue is recognized when electricity is delivered and is accounted for as rental income under the lease standard. The adoption of ASC 842 did not have an impact on the accounting policy for rental income from the Company’s PPAs in which it is the lessor. The Company elected the package of practical expedients available under ASC 842, which did not require the Company to reassess its lease classification from ASC 840. Additionally, the Company elected the practical expedient to not separate lease and non-lease components for lessors. This election allows energy (lease component) and environmental incentives or renewable energy certificates (non-lease components) under bundled PPAs to be accounted as a singular lease unit of account under ASC 842.

Deferred Financing Costs

Deferred Financing CostsFinancing costs incurred in connection with obtaining senior notes and term financing are deferred and amortized over the maturities of the respective financing arrangements using the effective interest method and are presented as a direct deduction from the carrying amount of the related debt (see Note 10. Long-term Debt for additional details), except for the costs related to the Company’s revolving credit facilities, which are presented as a non-current asset on the consolidated balance sheets within other assets.

Inventory

InventoryInventory consists of spare parts and is recorded at the lower of the weighted average cost of purchase or net realizable value within other current assets in the consolidated balance sheets. Spare parts are expensed to cost of operations in the consolidated statements of operations or capitalized to renewable energy facilities when installed or used, as appropriate.

Asset Retirement Obligations

Asset Retirement Obligations

Asset retirement obligations are accounted for in accordance with Accounting Standards Codification (“ASC”) 410-20, Asset Retirement Obligations. Retirement obligations associated with renewable energy facilities included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, and for which the timing and/or method of settlement may be conditional on a future event. Asset retirement obligations are recognized at fair value in the period in which they are incurred, and a corresponding asset retirement costs are recognized within the related renewable energy facilities. Over time, the asset retirement cost is depreciated over the estimated useful life of the related renewable energy facility, and the asset retirement obligation is accreted to its expected future value.

The Company generally reviews its asset retirement obligations annually, based on its review of updated cost studies, as necessary, and its evaluation of cost escalation factors. The Company evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant the application of the updated estimates to the asset retirement obligations. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognized as an increase or a decrease in the asset retirement cost to the extent applicable.

Revenue From Contracts With Customers

Revenue from Contracts with Customers

Adoption of Topic 606

On January 1, 2018, the Company adopted ASU No. 2014-09, Revenue from Contracts with Customers and ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (collectively referred to as “Topic 606”) for all revenue contracts in scope, which primarily included bundled energy and incentive sales through PPAs, individual REC sales, and upfront sales of federal and state incentive benefits recorded. The Company elected to use the contract modification practical expedient for purposes of computing the cumulative-effect adjustment recorded to the balances of stockholders’ equity as of January 1, 2018.

The Company evaluated the impact of Topic 606 as it relates to the individual sale of RECs. In certain jurisdictions, there may be a lag between physical generation of the underlying energy and the transfer of RECs to the customer due to administrative processes imposed by state regulations. Under the Company’s previous accounting policy, revenue was recognized as the underlying electricity was generated if the sale had been contracted with the customer. Based on the framework in Topic 606, for a portion of the existing individual REC sale arrangements where the transfer of control to the customer is determined to occur upon the transfer of the RECs, the Company currently recognizes revenue commensurate with the transfer of RECs to the customer as compared to the generation of the underlying energy under the previous accounting policy. Revenue recognition practices for the remainder of existing individual REC sale arrangements remain the same; that is, revenue is recognized based on the underlying generation of energy because the contracted RECs are produced from a designated facility and control of the RECs transfers to the customer upon generation of the underlying energy. The adoption of Topic 606, as it relates to the individual sale of RECs, resulted in an increase in accumulated deficit on January 1, 2018, of $20.5 million, net of tax, and net of $0.3 million and $4.5 million that were allocated to non-controlling interests and redeemable non-controlling interests, respectively. The adjustments for accumulated deficit and non-controlling interests are reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018, and the redeemable non-controlling interests adjustment is reflected within cumulative-effect adjustment in the redeemable non-controlling interests roll-forward presented in Note 18. Non-controlling Interests.

The Company evaluated the impact of Topic 606 as it relates to the upfront sale of investment tax credits (“ITCs”) through its lease pass-through fund arrangements. The amounts allocated to the ITCs were initially recorded as deferred revenue in the consolidated balance sheets, and subsequently, one-fifth of the amounts allocated to the ITCs was recognized annually as incentives revenue in the consolidated statements of operations based on the anniversary of each solar energy system’s placed-in-service date. The Company concluded that revenue related to the sale of ITCs through its lease pass-through arrangements should be recognized at the point in time when the related solar energy systems are placed in service. Previously, the Company recognized this revenue evenly over the five-year ITC recapture period. The Company concluded that the likelihood of a recapture event related to these assessments is remote. The adoption of Topic 606, as it relates to the upfront sale of ITCs, resulted in a decrease in accumulated deficit on January 1, 2018 of $40.9 million, net of tax, which is reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018. The impact on the Company’s results of operations for the year ended December 31, 2018 resulted in a decrease in non-cash deferred revenue recognition of $16.3 million.

PPA Rental Income

The majority of the Company’s energy revenue is derived from long-term PPAs accounted for as operating leases under ASC 840, Leases. Rental income under these lease agreements is recorded as revenue when the electricity is delivered to the customer. The Company adopted ASC 842, Leases on January 1, 2019, and elected certain of the practical expedients permitted in the issued standard, including the expedient that permits the Company to retain its existing lease assessment and classification.

Solar and Wind PPA Revenue

PPAs that are not accounted for under the scope of leases or derivatives are accounted for under Topic 606. The Company typically delivers bundled goods consisting of energy and incentive products for a singular rate based on a unit of generation at a specified facility over the term of the agreement. In these types of arrangements, the volume reflects total energy generation measured in Kilowatt hours (“kWhs”), which can vary period to period depending on system and resource availability. The contract rate per unit of generation (kWhs) is generally fixed at contract inception; however, certain pricing arrangements can provide for time-of-delivery, seasonal, or market index adjustment mechanisms over time. The customer is invoiced monthly equal to the volume of energy delivered multiplied by the applicable contract rate.

The Company considers bundled energy and incentive products within PPAs to be distinct performance obligations. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the

performance obligation is satisfied under Topic 606. The Company views the sale of energy as a series of distinct goods that is substantially the same and has the same pattern of transfer measured by the output method. Although the Company views incentive products in bundled PPAs to be performance obligations satisfied at a point in time, measurement of satisfaction and transfer of control to the customer in a bundled arrangement coincides with a pattern of revenue recognition with the underlying energy generation. Accordingly, the Company applied the practical expedient in Topic 606 as the right to consideration corresponds directly to the value provided to the customer to recognize revenue at the invoice amount for its standalone and bundled PPA contracts.

Commodity Derivatives

The Company has certain revenue contracts within its wind fleet that are accounted for as derivatives under the scope of ASC 815, Derivatives and Hedging. Amounts recognized within operating revenues, net in the consolidated statements of operations consist of cash settlements and unrealized gains and losses representing changes in fair value for the commodity derivatives that are not designated as hedging instruments. See Note 12. Derivatives for further discussion.

Regulated Solar and Wind Energy Revenue

Regulated solar and wind includes revenue generated by Saeta’s solar and wind operations in Spain, which are subject to regulations applicable to companies that generate production from renewable sources for facilities located in Spain. While Saeta’s Spanish operations are regulated by the Spanish regulator, the Company has determined that the Spanish entities do not meet the criteria of a rate-regulated entity under ASC 980 Regulated Operations, since the rates established by the Spanish regulator are not designed to recover the entity’s costs of providing its energy generation services. Accordingly, the Company applied Topic 606 to recognize revenue for these customer contract arrangements. The Company has distinct performance obligations to deliver electricity, capacity, and incentives which are discussed below.

The Company has a performance obligation to deliver electricity and these sales are invoiced monthly at the wholesale market price (subject to adjustments due to regulatory price bands that reduce market risk). The Company transfers control of the electricity over time and the customer receives and consumes the benefit simultaneously. Accordingly, the Company applied the practical expedient in Topic 606 as the right to consideration corresponds directly to the value provided to the customer to recognize revenue at the invoice amount for electricity sales.

The Company has a stand-ready performance obligation to deliver capacity in the Spanish electricity market in which these renewable energy facilities are located. Proceeds received by the Company from the customer in exchange for capacity are determined by a remuneration on an investment per unit of installed capacity that is determined by the Spanish regulators. The Company satisfies its performance obligation for capacity under a time-based measure of progress and recognizes revenue by allocating the total annual consideration evenly to each month of service.

Regulated Solar and Wind Incentive Revenue

For the Company’s Spanish solar renewable energy facilities, the Company has identified a performance obligation linked to an incentive that is distinct from the electricity and capacity deliveries discussed above. For solar technologies under the Spanish market, the customer makes an operating payment per MWh which is calculated based on the difference of a standard cost and an expected market price, both, determined by the Spanish regulator. The customer is invoiced monthly equal to the volume of energy produced multiplied by the regulated rate. The performance obligation is satisfied when the Company generates electricity from the solar renewable facility. The Company recognizes revenue based on the amount invoiced each month.

Amortization of Favorable and Unfavorable Rate-Revenue Contracts

The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. Intangible amortization of certain revenue contracts acquired in business combinations (favorable and unfavorable rate PPAs and REC agreements) is recognized on a straight-line basis over the remaining contract term. The current period amortization for favorable rate revenue contracts is reflected as a reduction to operating revenues, net, and amortization for unfavorable rate revenue contracts is reflected as an increase to operating revenues, net. See Note 7. Intangible Assets, Net and Goodwill for additional details.

Solar and Wind Incentive Revenue

The Company generates incentive revenue from individual incentive agreements relating to the sale of RECs and performance-based incentives to third-party customers that are not bundled with the underlying energy output. The majority of individual REC sales reflect a fixed quantity, fixed price structure over a specified term. The Company views REC products in these arrangements as distinct performance obligations satisfied at a point in time. Since the REC products delivered to the customer are not linked to the underlying generation of a specified facility, these RECs are recognized into revenue when delivered. The Company typically receives payment within 30 days of invoiced REC revenue.

For certain incentive contract arrangements, the quantity delivered to the customer is linked to a specific facility. The pattern of revenue recognition for these incentive arrangements is recognized over time coinciding with the underlying revenue generation from the related facility.

Income Taxes

Income Taxes

The Company accounts for income taxes using the liability method, which requires it to use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

The Company reports certain of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company’s financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company’s consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using enacted tax rates that are expected to be in effect when the deferred tax liabilities are expected to be realized or settled. Many factors are considered when assessing the likelihood of future realization of deferred tax assets, including recent earnings within taxing jurisdictions, expectations of future taxable income, the carry forward periods available and other relevant factors. The Company believes it is more likely than not that the future reversal of existing taxable temporary differences will allow the Company to realize deferred tax assets, net of valuation allowances. A valuation allowance is recorded to reduce the net deferred tax assets to an amount that is more-likely-than-not to be realized. Tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties related to uncertain tax benefits as a component of income tax expense. Changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits are recorded to income tax expense in the period such determination is made.

The Company releases the taxes deferred in AOCI as the individual units of account (i.e., derivative instruments in a cash flow hedge or net investment hedge relationships) are terminated, extinguished, sold or substantially liquidated.

Adoption of ASU 2018-02

During the fourth quarter of 2018, the Company early adopted ASU No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income addressing certain stranded income tax effects in AOCI resulting from the U.S. government’s enactment of the Tax Cuts and Jobs Act (the “Tax Act”) on December 22, 2017. The adoption of ASU No. 2018-12 resulted in reclassifying $9.4 million of stranded tax effects on the net unrealized gains on derivatives designated as hedging instruments in a cash flow relationship from AOCI to accumulated deficit. The reclassification is reflected as an increase to accumulated deficit within the cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018, and an increase to the opening balance of AOCI as of January 1, 2018.

Variable Interest Entities

Variable Interest Entities

The Company assesses entities for consolidation in accordance with ASC 810. The Company consolidates variable interest entities (“VIEs”) in renewable energy facilities when determined to be the primary beneficiary. VIEs are entities that lack one or more of the characteristics of a voting interest entity (“VOE”). The Company has a controlling financial interest in a VIE when its variable interest or interests provide it with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

VOEs are entities in which (i) the total equity investment at risk is sufficient to enable the entity to finance its activities independently and (ii) the equity holders have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the losses of the entity and the right to receive the residual returns of the entity. The usual condition for a controlling financial interest in a voting interest entity is ownership of a majority voting interest. If the Company has a majority voting interest in a voting interest entity, the entity is consolidated.

For the Company’s consolidated VIEs, the Company has presented on its consolidated balance sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of its consolidated VIEs for which creditors do not have recourse to the Company’s general assets outside of the VIE.

Noncontrolling Interests and Hypothetical Liquidation at Book Value (HLBV)

Non-controlling Interests and Hypothetical Liquidation at Book Value (“HLBV”)

Non-controlling interests represent the portion of net assets in consolidated entities that are not owned by the Company and are reported as a component of equity in the consolidated balance sheets. Non-controlling interests in subsidiaries that are redeemable either at the option of the holder or at fixed and determinable prices at certain dates in the future are classified as redeemable non-controlling interests in subsidiaries between liabilities and stockholders’ equity in the consolidated balance sheets. Redeemable non-controlling interests that are currently redeemable or redeemable after the passage of time are adjusted to their redemption value as changes occur. The Company applies the guidance in ASC 810-10 along with the Securities and Exchange Commission (“SEC”) guidance in ASC 480-10-S99-3A in the valuation of redeemable non-controlling interests.

The Company has determined the allocation of economics between the controlling party and the third party for non-controlling interests does not correspond to ownership percentages for certain of its consolidated subsidiaries. In order to reflect the substantive profit sharing arrangements, the Company has determined that the appropriate methodology for determining the value of non-controlling interests is a balance sheet approach using the HLBV method. Under the HLBV method, the amounts reported as non-controlling interest on the consolidated balance sheets represent the amounts the third party investors could hypothetically receive at each balance sheet reporting date based on the liquidation provisions of the respective operating partnership agreements. HLBV assumes that the proceeds available for distribution are equivalent to the unadjusted, stand-alone net assets of each respective partnership, as determined under U.S. GAAP. The third party non-controlling interests in the consolidated statements of operations and statements of comprehensive loss are determined based on the difference in the carrying amounts of non-controlling interests on the consolidated balance sheets between reporting dates, adjusted for any capital transactions between the Company and third party investors that occurred during the respective period. 

Where, prior to the commencement of operating activities for a respective renewable energy facility, HLBV results in an immediate change in the carrying value of non-controlling interests on the consolidated balance sheets due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company defers the recognition of the respective adjustments and recognizes the adjustments in non-controlling interest on the consolidated statements of operations on a straight-line basis over the expected life of the underlying assets giving rise to the respective difference. Similarly, where the Company has acquired a controlling interest in a partnership and there is a resulting difference between the initial fair value of non-controlling interest and the value of non-controlling interest as measured using HLBV, the Company initially records non-controlling interests at fair value and amortizes the resulting difference over the remaining life of the underlying assets.

Contingencies

ContingenciesThe Company is involved in conditions, situations or circumstances in the ordinary course of business with possible gain or loss contingencies that will ultimately be resolved when one or more future events occur or fail to occur. If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, that amount will be accrued. When no amount within the range is a better estimate than any other amount, the minimum amount in the range will be accrued. The Company continually evaluates uncertainties associated with loss contingencies and records a charge equal to at least the minimum estimated liability for a loss contingency when both of the following conditions are met: (i) information available prior to the issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements; and (ii) the loss or range of loss can be reasonably estimated. Legal costs are expensed when incurred. Gain contingencies are not recorded until realized or realizable.

Derivative Financial Instruments

Derivative Financial Instruments

Adoption of ASU 2017-12

On January 1, 2018, the Company adopted ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities which primarily resulted in simplification of the assessment of hedge

effectiveness for derivatives designated in a qualifying cash flow relationship, and the periodic recognition of gains and losses related to certain components of AOCI. The Company adopted ASU No. 2017-12 using the modified retrospective transition method resulting in a cumulative-effect adjustment of $4.2 million, net of tax of $1.6 million, representing a decrease in accumulated deficit and AOCI, which is reflected within cumulative-effect adjustment in the consolidated statements of stockholders’ equity for the year ended December 31, 2018.

Initial Recognition

The Company recognizes its derivative instruments as assets or liabilities at fair value in the consolidated balance sheets on a trade date basis unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated as part of a hedging relationship and the type of hedging relationship.

Derivatives that qualify and are designated for hedge accounting are classified as either hedges of the variability of expected future cash flows to be received or paid related to a recognized asset or liability (cash flow hedges) or hedges of the exposure to foreign currency of a net investment in a foreign operation (net investment hedges).

The Company also uses derivative contracts outside the hedging program to manage foreign currency risk associated with intercompany loans.

Subsequent Measurement

The change in fair value of components included in the effectiveness assessment of derivative instruments designated as cash flow hedges is recognized as a component of OCI and reclassified into earnings on a trade date basis in the period that the hedged transaction affects earnings. The change in fair value of components included in the effectiveness assessment of foreign currency contracts designated as net investment hedges is recorded in cumulative translation adjustments within AOCI and reclassified into earnings when the foreign operation is sold or substantially liquidated.

The change in fair value of derivative contracts intended to serve as economic hedges that are not designated as hedging instruments is reported as a component of earnings in the consolidated statements of operations.

Cash flows from derivative instruments designated as net investment hedges and non-designated derivatives used to manage foreign currency risks associated with intercompany loans are classified as investing activities in the

consolidated statements of cash flows. Cash flows from all other derivative instruments are classified as operating activities in the consolidated statements of cash flows.

Fair Value Measurements

Fair Value Measurements

The Company performs fair value measurements defined as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required to be recorded at their fair values, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer restrictions and risk of nonperformance.

In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:

•Level 1: Quoted prices in active markets for identical assets or liabilities;

•Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; or

•Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair values of the assets or liabilities.

The Company maintains various financial instruments recorded at cost in the consolidated balance sheets that are not required to be recorded at fair value. For cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and other current assets, accounts payable and accrued expenses and other current liabilities and due to affiliates, net, the carrying

amount approximates fair value because of the short-term maturity of the instruments. See Note 13. Fair Value of Financial Instruments for disclosures related to the fair value of the Company’s derivative instruments and long-term debt.

Foreign Currency

Foreign Currency

The Company’s reporting currency is the U.S. dollar. Certain of the Company’s subsidiaries maintain their records in local currencies other than the U.S. dollar, which are their functional currencies. When a subsidiary’s local currency is considered its functional currency, the Company translates its assets and liabilities to U.S. dollars using exchange rates in effect at date of the financial statements and its revenue and expense accounts to U.S. dollars at average exchange rates for the period. Cumulative translation adjustments are reported in AOCI in stockholders’ equity. Cumulative translation adjustments are reclassified from AOCI to earnings only when realized upon sale or upon complete or substantially complete liquidation of an investment in a foreign subsidiary. Transaction gains and losses and changes in fair value of the Company’s foreign exchange derivative contracts not accounted for under hedge accounting are included in results of operations as recognized.

Business Combinations and Acquisitions of Assets

Business Combinations and Acquisitions of Assets

The Company applies the definition of a business in ASC 805, Business Combinations to determine whether it is acquiring a business or a group of assets.

The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, acquisition costs related to business combinations are expensed as incurred.

When the Company acquires a renewable energy business, the purchase price is allocated to (i) the acquired tangible assets and liabilities assumed, primarily consisting of land, plant and long-term debt, (ii) the identified intangible assets and liabilities, primarily consisting of the value of favorable and unfavorable rate PPAs, REC agreements, the licensing contracts and in-place value of market rate PPAs, (iii) non-controlling interests, and (iv) other working capital items based in each case on their fair values. The excess of the purchase price over the estimated fair value of net assets acquired is recorded as goodwill.

The Company generally uses independent appraisers to assist with the estimates and methodologies used such as a replacement cost approach, or an income approach or excess earnings approach. Factors considered by the Company in its analysis include considering current market conditions and costs to construct similar facilities. The Company also considers information obtained about each facility as a result of its pre-acquisition due diligence in estimating the fair value of the tangible and intangible assets and liabilities acquired or assumed. In estimating the fair value, the Company also establishes estimates of energy production, current in-place and market power purchase rates, tax credit arrangements and operating and maintenance costs. A change in any of the assumptions above, which are subjective, could have a significant impact on the results of operations.

The allocation of the purchase price directly affects the following items in the consolidated financial statements:

•The amount of purchase price allocated to the various tangible and intangible assets, liabilities and non-controlling interests on the balance sheet;

•The amounts allocated to the value of favorable and unfavorable rate PPAs and REC agreements are amortized to revenue over the remaining non-cancelable terms of the respective arrangement. The amounts allocated to all other tangible assets and intangibles are amortized to depreciation or amortization expense; and

•The period of time over which tangible and definite-lived intangible assets and liabilities are depreciated or amortized varies, and thus, changes in the amounts allocated to these assets and liabilities will have a direct impact on the Company’s results of operations.

ASC 805 allows the acquirer to report provisional amounts and adjust them for a period of time up to one year after the acquisition date (the “measurement period”) while the Company obtains information about the facts and circumstances that existed as of the acquisition date.

Acquisition of Assets

he Company recognizes and measures the acquired assets based on the cost of the acquisitions, generally being the consideration transferred to the seller and typically includes the direct transaction costs related to the acquisition. The Company allocates the total cost of acquisition to the individual assets acquired or liabilities assumed based on their relative fair values generally similar to the allocation of the purchase price in a business combination. No goodwill is recognized in an asset acquisition.

Assets Held for Sale

Assets Held for Sale

The Company records assets held for sale at the lower of the carrying value or fair value less costs to sell. The following criteria are used to determine if property is held for sale: (i) management has the authority and commits to a plan to sell the property; (ii) the property is available for immediate sale in its present condition; (iii) there is an active program to locate a buyer and the plan to sell the property has been initiated; (iv) the sale of the property is probable within one year; (v) the property is being actively marketed at a reasonable price relative to its current fair value; and (vi) it is unlikely that the plan to sell will be withdrawn or that significant changes to the plan will be made.

In determining the fair value of the assets less costs to sell, the Company considers factors including current sales prices for comparable assets in the region, recent market analysis studies, appraisals and any recent legitimate offers. If the estimated fair value less costs to sell of an asset is less than its current carrying value, the asset is written down to its estimated fair value less costs to sell. Due to uncertainties in the estimation process, it is reasonably possible that actual results could differ from the estimates used in the Company’s historical analysis. The Company’s assumptions about project sale prices require significant judgment because the current market is highly sensitive to changes in economic conditions. The Company estimates the fair values of assets held for sale based on current market conditions and assumptions made by management, which may differ from actual results and may result in additional impairments if market conditions deteriorate.

When assets are classified as held for sale, the Company does not record depreciation or amortization for the respective renewable energy facilities or intangibles.

Stock-Based Compensation

Stock-Based Compensation

Stock-based compensation expense for all share-based payment awards to certain employees who provide services to the Company is based on the estimated grant-date fair value. The Company recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award vesting term. For ratable awards, the Company recognizes compensation costs for all grants on a straight-line basis over the requisite service period of the entire award. The Company recognizes the effect of forfeitures in compensation costs when they occur.

Restructuring

RestructuringThe Company accounts for restructuring costs in accordance with ASC 712 and ASC 420, as applicable. In connection with the consummation of the Merger and the relocation of the Company’s headquarters to New York, New York, the Company announced a restructuring plan that went into effect upon the closing of the Merger.

Recently Adopted Accounting Standards - Additional Guidance Adopted in 2019 and Recently Issued Accounting Standards Not Yet Adopted

Recently Adopted Accounting Standards - Additional Guidance Adopted in 2019

In October 2018, the FASB issued ASU No. 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (“SOFR”) Overnight Index Swap (“OIS”) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes. This ASU expands the list of United States (“U.S.”) benchmark interest rates permitted in the application of hedge accounting by adding the SOFR as a permissible U.S. benchmark rate. The Company does not have any derivative instruments

indexed to SOFR as a benchmark interest rate, accordingly, the adoption of ASU No. 2018-16 as of January 1, 2019 did not have an impact on the Company’s consolidated financial statements.

Recently Issued Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), to provide financial statement users with more useful information about the current expected credit losses (“CECL”). This ASU changes how entities measure credit losses on financial instruments and the timing of when such losses are recognized by utilizing a lifetime expected credit loss measurement. The guidance is effective for fiscal years and interim periods within those years beginning after January 1, 2020. The Company does not expect the adoption of Topic 326 to have a material impact on its results of operations.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement. This ASU removes some disclosure requirements, modifies others, and adds some new disclosure requirements. The guidance is effective January 1, 2020, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40) Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. This ASU amends the definition of a hosting arrangement and requires a customer in a cloud computing arrangement that is a service contract to follow the internal use software guidance in ASC 350-402 to determine which implementation costs to capitalize as assets. Capitalized implementation costs are amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. The guidance is effective January 1, 2020, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In October 2018, the FASB issued ASU No. 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities. The amendments in this ASU require reporting entities to consider indirect interests held through related parties under common control for determining whether fees paid to decision makers and service provider are variable interests. These indirect interests should be considered on a proportional basis rather than as the equivalent of a direct interest in its entirety (as currently required in U.S. GAAP). The guidance is effective January 1, 2020, with early adoption permitted. Entities are required to apply the amendments in this guidance retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this ASU simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740, Income Taxes. The amendments also improve consistent application or and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The guidance is effective January 1, 2021, with early adoption permitted. The Company does not expect the effect of the new guidance to be material on its consolidated financial statements.

(Loss) Earnings per Share

Basic (loss) earnings per share is computed by dividing net (loss) income attributable to Class A common stockholders by the number of weighted average ordinary shares outstanding during the period. Diluted (loss) earnings per share is computed by adjusting basic (loss) income per share for the impact of the equivalent weighted average dilutive common shares outstanding during the period unless the impact is anti-dilutive. Common equivalent shares represent the incremental shares issuable for unvested restricted Common Stock.

Unvested RSAs that contain non-forfeitable rights to distributions are treated as participating securities and are included in the (loss) earnings per share computation using the two-class method. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that would otherwise have been available to common stockholders. This method determines loss per share based on distributions declared on common stock and participating securities (i.e., distributed earnings), as well as participation rights of participating securities in any undistributed earnings. Undistributed losses are not allocated to participating securities since they are not contractually obligated to share in the losses of the Company. The numerator for undistributed (loss) earnings per share is also adjusted by the amount of deemed distributions related to the accretion of redeemable non-controlling interest since the redemption value of the non-controlling interest was considered to be at an amount other than fair value (and was considered a right to an economic distribution that differed from other common stockholders) and as accretion adjustments were recognized in additional paid-in capital and not within net (loss) income attributable to Class A common stockholders.

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Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Total - Parent	Common Stock Class A Common Stock Issued	Common Stock Class B Common Stock Issued	Additional Paid-in Capital	Accumulated Deficit	AOCI Attributable to Parent	Common Stock Held in Treasury	Total - Non-controlling Interests	Noncontrolling Interest Capital	Non-controlling Interests - Accumulated Deficit	Non-controlling Interests - Accumulated Other Comprehensive Loss
Beginning balance (in shares) at Dec. 31, 2016			92,477,000	48,202,000				(254,000)
Beginning balance at Dec. 31, 2016	$ 2,729,494	$ 1,260,347	$ 920	$ 482	$ 1,467,108	$ (227,050)	$ 22,912	$ (4,025)	$ 1,469,147	$ 1,792,295	$ (308,742)	$ (14,406)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net SunEdison investment	9,768	7,019			7,019				2,749	2,749
Equity reallocation	0	8,780			8,780				(8,780)	(8,780)
SunEdison exchange (in shares)			48,202,000	(48,202,000)
SunEdison exchange	0	640,809	$ 482	$ (482)	641,452		(643)		(640,809)	(835,662)	194,210	643
Issuance of equity (shares)			6,493,000
Issuance of Class A common stock	0		$ 65		(65)
Write-off of payables to SunEdison	15,677	15,677			15,677
Stock-based compensation (in shares)			1,414,000					(246,000)
Stock-based compensation	12,021	12,021	$ 19		14,689			$ (2,687)
Net (loss) income	(237,899)	(160,154)				(160,154)			(77,745)		(77,745)
Special Distribution payment	(285,497)	(285,497)			(285,497)
Other comprehensive income (loss)	40,406	25,749					25,749		14,657			14,657
Sale of membership interests and contributions from non-controlling interests	6,935								6,935	6,935
Distributions to non-controlling interests	(23,345)								(23,345)	(23,345)
Deconsolidation of non-controlling interest	(8,713)								(8,713)	(8,713)
Accretion of redeemable non-controlling interest	(6,729)	(6,729)			(6,729)
Reclassification of Invenergy Wind Interest from redeemable non-controlling interests to non-controlling interests	131,822								131,822	131,822
Other	$ 3,772	9,691			9,691				(5,919)		(5,919)
Ending balance (in shares) at Dec. 31, 2017	148,086,000		148,586,000	0				(500,000)
Ending balance at Dec. 31, 2017	$ 2,387,712	1,527,713	$ 1,486	$ 0	1,872,125	(387,204)	48,018	$ (6,712)	859,999	1,057,301	(198,196)	894
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of equity (shares)	61,056,000		61,056,000
Issuance of Class A common stock	$ 650,881	650,881	$ 610		650,271
Purchase of treasury stock (in shares)	0
Write-off of payables to SunEdison	$ 0
Stock-based compensation (in shares)	0							0
Stock-based compensation	$ 257	257			257			$ 0
Net (loss) income	(162,536)	12,380				12,380			(174,916)		(174,916)
Special Distribution payment	(135,234)	(135,234)			(135,234)
Other comprehensive income (loss)	(13,761)	(12,984)					(12,984)		(777)			(777)
Contributions from non-controlling interests	7,685								7,685	7,685
Distributions to non-controlling interests	(24,128)								(24,128)	(24,128)
Accretion of redeemable non-controlling interest	0
Purchase of redeemable non-controlling interests	817	817			817
Other	$ 3,123	3,210			3,199		11		(87)	(87)
Ending balance (in shares) at Dec. 31, 2018	209,142,000		209,642,000	0				(500,000)
Ending balance at Dec. 31, 2018	$ 2,734,922	2,067,454	$ 2,096	$ 0	2,391,435	(359,603)	40,238	$ (6,712)	667,468	1,040,771	(373,420)	117
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of equity (shares)	2,982,000		17,889,000
Issuance of Class A common stock	$ 298,768	298,768	$ 179		298,589
Purchase of treasury stock (in shares)	543,000							543,000
Purchase of treasury stock	$ 8,353	8,353						$ 8,353
Write-off of payables to SunEdison	$ 0
Stock-based compensation (in shares)	13,000		21,000					(8,000)
Stock-based compensation	$ 390	390	$ 1		492			$ (103)
Net (loss) income	(194,602)	(148,684)				(148,684)			(45,918)		(45,918)
Distributions to Class A common stockholders	171,503				171,503
Other comprehensive income (loss)	(29,217)	(28,593)					(28,593)		(624)			(624)
Contributions from non-controlling interests	6,356								6,356	6,356
Distributions to non-controlling interests	(25,366)								(25,366)	(25,366)
Accretion of redeemable non-controlling interest	0
Purchase of non-controlling interests	(1,080)	(687)			(687)				(393)	(393)
Non-cash redemption of redeemable non-controlling interests	(7,345)	(7,345)			(7,345)
Purchase of redeemable non-controlling interests	1,910	1,910			1,910
Other	$ 3,028								3,028	3,028
Ending balance (in shares) at Dec. 31, 2019	226,501,000		227,552,000	0				(1,051,000)
Ending balance at Dec. 31, 2019	$ 2,607,908	$ 2,003,357	$ 2,276	$ 0	$ 2,512,891	$ (508,287)	$ 11,645	$ (15,168)	$ 604,551	$ 1,024,396	$ (419,338)	$ (507)

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Renewable Energy Facilities (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Renewable Energy Facilities

Renewable energy facilities, net consists of the following: 

	As of December 31,
(In thousands)	2019		2018
Renewable energy facilities in service, at cost1	$	8,584,243	$	7,298,371
Less accumulated depreciation - renewable energy facilities	(1,191,056)		(833,844)
Renewable energy facilities in service, net	7,393,187		6,464,527
Construction in progress - renewable energy facilities	12,274		5,499
Total renewable energy facilities, net	$	7,405,461	$	6,470,026

———

(1)As discussed in Note 2. Summary of Significant Accounting Policies and Note 8. Leases, on January 1, 2019, the Company recognized $262.1 million right-of-use of assets related to operating leases as a result of the adoption of Topic 842, which is included within renewable energy facilities. The amount of right-of-use of assets as of December 31, 2019 was $288.3 million.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Letters of Credit

The Company’s customers, vendors and regulatory agencies often require the Company to post letters of credit in order to guarantee performance under certain contracts and agreements. The Company is also required to post letters of credit to secure obligations under various swap agreements and leases and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. The amount that can be drawn under some of these letters of credit may be increased from time to time subject to the satisfaction of certain conditions. As of December 31, 2019, the Company had outstanding letters of credit drawn under the Revolver of $115.5 million and outstanding project-level letters of credit of $266.9 million, drawn under certain project-level financing agreements, respectively, compared to $99.5 million and $197.7 million as of December 31, 2018, respectively.

Guaranty Agreements

The Company and its subsidiaries have entered into guaranty agreements to certain of their institutional tax equity investors and financing parties in connection with their tax equity financing transactions. These agreements do not guarantee the returns targeted by the tax equity investors or financing parties, but rather support any potential indemnity payments payable under the tax equity agreements, including related to management of tax partnerships and recapture of tax credits or renewable energy grants in connection with transfers of the Company’s direct or indirect ownership interests in the tax partnerships to entities that are not qualified to receive those tax benefits.

The Company and its subsidiaries have also provided guaranties in connection with acquisitions of third-party assets or to support project-level contractual obligations, including renewable energy credit sales agreements. The Company and its subsidiaries have also provided other capped or limited contingent guaranties and other support obligations with respect to certain project-level indebtedness.

The amounts of the above guaranties often are not explicitly stated and the overall maximum amount of the related obligations cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guaranties. The Company believes the probability of payments being demanded under these guaranties is remote and no material amounts have been recognized for the underlying fair value of guaranty obligations.

Operating Leases

The Company has operating leases for renewable energy production facilities, land, office space, transmission lines, vehicles and other operating equipment. See Note 8. Leases for details of the Company’s lease arrangements, including rental expense, and future commitments under operating leases.

Long-Term Service Agreements

On August 10, 2018, the Company executed an 11-year framework agreement with affiliates of General Electric (“GE”) that, among other things, provides for the roll out, subject to receipt of third-party consents, of project level, long-term service agreements (“LTSA”) for turbine operations and maintenance “O&M”, as well as other balance of plant services across the Company’s 1.6 GW North American wind fleet. As of December 31, 2019, 15 of 16 project-level LTSAs were in place. Pursuant to the LTSAs with GE, if a facility generates less than the resource-adjusted amount of guaranteed generation, GE is liable to make a payment to the Company, as liquidated damages, corresponding to the amount of operating revenues lost due to such shortfall, after taking into account certain exclusions. In addition, if a facility generates more than the resource-adjusted amount of guaranteed generation, the Company has an obligation to pay a bonus to GE.

On November 1, 2019, the Company executed a 10-year framework agreement with SMA Solar Technology that, among other things, provides for the roll out, subject to receipt of third-party consents, of project level LTSAs for solar O&M, as well as other balance of plant services across the Company’s North American solar fleet.

Legal Proceedings

The Company is not a party to any material legal proceedings other than various administrative and regulatory proceedings arising in the ordinary course of the Company’s business or as described below. While the Company cannot predict with certainty the ultimate resolution of such proceedings or other claims asserted against the Company, certain of the claims, if adversely concluded, could result in substantial damages or other relief.

Claim relating to First Wind Acquisition

On May 27, 2016, D.E. Shaw Composite Holdings, L.L.C. and Madison Dearborn Capital Partners IV, L.P., as the representatives of the sellers (the “First Wind Sellers”) filed an amended complaint for declaratory judgment against TerraForm Power and Terra LLC in the Supreme Court of the State of New York alleging breach of contract with respect to the Purchase and Sale Agreement, dated as of November 17, 2014 (the “FW Purchase Agreement”) between, among others, SunEdison, Inc. (“SunEdison”), TerraForm Power, Terra LLC and the First Wind Sellers. The amended complaint alleges that Terra LLC and SunEdison became jointly obligated to make $231.0 million in earn-out payments in respect of certain development assets SunEdison acquired from the First Wind Sellers under the FW Purchase Agreement, when those payments were purportedly accelerated by SunEdison’s bankruptcy and by the resignations of two SunEdison employees. The amended complaint further alleges that TerraForm Power, as guarantor of certain Terra LLC obligations under the FW Purchase Agreement, is liable for this sum. In addition, the plaintiffs have claimed legal costs and expenses and, under applicable New York law, their claim accrues interest at a non-compounding rate of 9% per annum.

The defendants filed a motion to dismiss the amended complaint on July 5, 2016, on the ground that, among other things, SunEdison is a necessary party to this action. On February 6, 2018, the court denied the Company’s motion to dismiss after which document discovery began. In April 2019, Terra LLC filed an amended answer to the amended complaint. The Company cannot predict the impact on this litigation of any information that may become available in discovery. Document discovery and depositions are now substantially completed and new pretrial schedule has been agreed between the parties and approved by the court. Subsequent to year end, on January 24, 2020, the parties filed their respective motions to dismiss and on February 12, 2020, the parties filed their respective opposition briefs. The court’s ruling on the motions to dismiss is expected before the end of 2020.

The Company believes the First Wind Sellers’ allegations are without merit and will contest them vigorously. However, the Company cannot predict with certainty the ultimate resolution of any proceedings brought in connection with such a claim.

Whistleblower Complaint by Francisco Perez Gundin

On May 18, 2016, the Company’s former Director and Chief Operating Officer, Francisco Perez Gundin (“Mr. Perez”), filed a complaint against the Company, TerraForm Global, Inc. (“TerraForm Global”) and certain individuals, with the United States Department of Labor. The complaint alleged that the defendants engaged in a retaliatory termination of Mr. Perez’s employment after he allegedly voiced concerns to SunEdison’s Board of Directors about public representations made by SunEdison officers regarding SunEdison’s liquidity position, and after he allegedly voiced his opposition to transactions that he alleged were self-interested and which he alleged SunEdison forced on the Company. He alleged that the Company participated in SunEdison’s retaliatory termination by constructively terminating his position as Chief Operating Officer of the Company in connection with SunEdison’s constructive termination of his employment. He sought lost wages, bonuses, benefits, and other money that he alleged he would have received if he had not been subjected to the allegedly retaliatory termination. The Company’s Position Statement in response to the complaint was filed in October 2016.

On February 21, 2017, Mr. Perez filed Gundin v. TerraForm Global, Inc. et al. against TerraForm Power, TerraForm Global and certain individuals as defendants in the United States District Court for the District of Maryland, which was subsequently transferred to the U.S. District Court for the Southern District of New York (“SDNY”). The complaint asserted claims for retaliation, breach of the implied covenant of good faith and fair dealing and promissory estoppel based on the same allegation in Mr. Perez’s Department of Labor complaint. On March 8, 2018, Mr. Perez voluntarily dismissed the federal action without prejudice. On December 27, 2018, the proceeding before the Department of Labor was dismissed, which Mr. Perez appealed on January 25, 2019. On August 27, 2019, pursuant to Mr. Perez’s offer to settle the dispute, a definitive settlement agreement was executed between the Company and Mr. Perez. The settlement with Mr. Perez was paid entirely from insurance proceeds.

Whistleblower Complaint by Carlos Domenech Zornoza

On May 10, 2016, the Company’s former Director and Chief Executive Officer, Carlos Domenech Zornoza (“Mr. Domenech”), filed a complaint against the Company, TerraForm Global and certain individuals, with the United States Department of Labor. The complaint alleges that the defendants engaged in a retaliatory termination of Mr. Domenech’s employment on November 20, 2015, after he allegedly voiced concerns to SunEdison’s Board of Directors about public representations made by SunEdison officers regarding SunEdison’s liquidity position, and after he allegedly voiced his opposition to transactions that he alleges were self-interested and which he alleges SunEdison forced on the Company. He alleges that the Company participated in SunEdison’s retaliatory termination by terminating his position as Chief Executive

Officer of the Company in connection with SunEdison’s termination of his employment. He seeks lost wages, bonuses, benefits, and other money that he alleges that he would have received if he had not been subjected to the allegedly retaliatory termination. The Company’s Position Statement in response to the complaint was filed in October 2016.

On February 21, 2017, Mr. Domenech filed Domenech Zornoza v. TerraForm Global, Inc. et. al against TerraForm Power, TerraForm Global and certain individuals as defendants in the United States District Court for the District of Maryland. The complaint asserted claims for retaliation, breach of the implied covenant of good faith and fair dealing and promissory estoppel based on the same allegations in Mr. Domenech’s Department of Labor complaint. On March 15, 2017, the Company filed notice with the Judicial Panel on Multidistrict Litigation to transfer this action to the SDNY where other cases not involving the Company relating to the SunEdison bankruptcy are being tried. The plaintiff opposed the transfer. However, the transfer was approved by the Judicial Panel on Multidistrict Litigation. On November 6, 2017, TerraForm Power and the other defendants filed a motion to dismiss Mr. Domenech’s complaint, and Mr. Domenech filed a response on December 21, 2017. On March 8, 2018, Mr. Domenech voluntarily dismissed the federal action without prejudice, which would permit the action to be refiled.

On August 16, 2018, Mr. Domenech filed a second complaint with the United States District Court for the District of Maryland, with substantially the same allegations. On October 17, 2018, the Company filed notice with the Judicial Panel on Multidistrict Litigation to transfer this action to the SDNY. The Plaintiff opposed the transfer. However, the transfer was approved by the Judicial Panel on Multidistrict Litigation. On March 15, 2019, the Company, TerraForm Global, and several individual defendants filed a joint motion to dismiss Mr. Domenech’s complaint. Mr. Domenech filed a response on April 15, 2019, and the Company, TerraForm Global, and the individual defendants filed a reply on April 25, 2019. On December 9, 2019, the Court dismissed two of his three claims against the Company and TerraForm Global. On January 22, 2020, the Company filed an answer to Mr. Domenech’s remaining, narrowed claim of retaliatory termination.

The Company reserved for its estimated loss related to this complaint in 2016, which was not considered material to the Company’s consolidated results of operations, and this amount remains accrued as of December 31, 2019. However, the Company is unable to predict with certainty the ultimate resolution of these proceedings.

Derivative Class Action

On September 19, 2019, lead plaintiff Martin Rosson filed a derivative and class action lawsuit in the Delaware Court of Chancery on behalf of the Company, himself, and other minority stockholders of the Company against Brookfield and certain of its affiliates (including the Company as a nominal defendant). The complaint alleges that the defendant controlling stockholders breached their fiduciary duty to minority stockholders because the Company undertook a private placement of the Company’s stock on terms that the complaint alleges are unfair, instead of pursuing a public offering. The proceeds of the private placement were used to fund the acquisition by the Company of Saeta and had been approved by the Conflicts Committee of the Company’s Board of Directors. The complaint seeks the rescission and invalidation of the private placement and payment to the Company of rescissory damages, among other relief. In a related development, on October 15, 2019, the Company received a demand letter for the production of books and records pursuant to 8 Del. C. § 220 to allow counsel to the City of Dearborn Policy and Retirement System (a purported shareholder of the Company) to investigate potential breaches of fiduciary duty by Brookfield and the Company’s Board of Directors in connection with the funding of the acquisition of Saeta. Subsequent to year end, on January 27, 2020, the City of Dearborn Police and Retirement System filed a derivative and class action lawsuit in the Delaware Court of Chancery on behalf of the Company, itself, and other minority stockholders of the Company against Brookfield and certain of its affiliates (including the Company as a nominal defendant) alleging claims similar to those set forth in the Rosson complaint. The City of Dearborn Police and Retirement System and Martin Rosson agreed, with the consent of the Company and Brookfield, to consolidate their respective claims and such consolidation was approved by the Court during the first quarter of 2020. While the Company believes that these claims are without merit, it cannot predict with certainty the ultimate resolution of any proceedings brought in connection with these claims.

Chile Project Arbitration

              On September 5, 2016, Compañía Minera del Pacífico (“CMP”) submitted demands for arbitration against the subsidiary of the Company that owns its solar project located in Chile and against the latter’s immediate holding company to the Santiago Chamber of Commerce’s Center for Arbitration and Mediation (“CAM”). The demands alleged, among other things, that the Chile project was not built, operated and maintained according to the relevant standards using prudent utility practices as required by the electricity supply agreement (the “Contract for Difference”) between the parties, entitling them to terminate the Contract for Difference. CMP further alleged that it is entitled to damages based on alleged breaches of a call option agreement entered into by the parties.

In June 2019, the CAM issued two rulings in which it unanimously rejected the claims made by CMP. CMP indicated

that they would not seek to appeal the ruling and the window in which they are permitted to appeal the ruling has now closed.

Other matters

Two of the Company’s project level subsidiaries are parties to litigation that is seeking to recover alleged underpayments of tax grants under Section 1603 of the American Recovery and Reinvestment Tax Act from the U.S. Department of Treasury (“U.S. Treasury”). These project level subsidiaries filed complaints at the Court of Federal Claims on March 28, 2014. The U.S. Treasury counterclaimed and both claims went to trial in July 2018. In January 2019, the Court of Federal Claims entered judgments against each of the project level subsidiaries for approximately $10.0 million in the aggregate. These judgments are being appealed. The project level subsidiaries expect that losses, if any, arising from these claims would be covered pursuant to an indemnity and, accordingly, the Company recognized a corresponding indemnification asset within other current assets in the consolidated balance sheets as of December 31, 2019 and December 31, 2018.

Issuance of Shares upon Final Resolution of Certain Litigation Matters

Pursuant to the definitive merger and sponsorship agreement (the “Merger Agreement”) entered into with Orion Holdings on March 6, 2017, the Company has agreed to issue additional shares of Common Stock to Orion Holdings for no additional consideration in respect of the Company’s net losses, such as out-of-pocket losses, damages, costs, fees and expenses, in connection with the obtainment of a final resolution of certain specified litigation matters (including the litigation brought by the First Wind Sellers, Mr. Perez and Mr. Domenech described above) within a prescribed period following the final resolution of such matters. The number of additional shares of Common Stock to be issued to Orion Holdings is subject to a pre-determined formula as set forth in the Merger Agreement and is described in greater detail in the Company’s Definitive Proxy Statement on Schedule 14A filed with the SEC on September 6, 2017. The issuance of additional shares to Orion Holdings would dilute the holdings of the Company’s common stockholders and may negatively affect the value of the Company’s Common Stock.

The settlement with Mr. Perez was paid entirely from insurance proceeds and no shares have been issued to Brookfield in connection with the settlement. As of the date hereof, the Company is unable to predict the quantum of any net losses arising from any of the litigation brought by the First Wind Sellers or Mr. Domenech described above or the number of additional shares, if any, that may be required to be issued to Orion Holdings pursuant to the terms of the Merger Agreement in connection with any final resolution of such matters.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Stockholders' Equity

STOCKHOLDERS’ EQUITY

TerraForm Power, Inc. has 100,000,000 authorized shares of preferred stock of par value $0.01 per share, and 1,200,000,000 authorized shares of Common Stock of par value $0.01 per share. There are no other authorized classes of shares and the Company does not have any issued shares of preferred stock. As of December 31, 2019, the combined ownership of affiliates of Brookfield was approximately 62%.

On January 11, 2020, the Company received an unsolicited, non-binding proposal (the “Brookfield Proposal”) from Brookfield Renewable, an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% already held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board of Directors of the Company (the “Board”) consisting solely of independent Directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a special committee (the “Special Committee”) of non-executive, disinterested and independent Directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the

Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. On March 16, 2020, on the unanimous recommendation of the Special Committee and with the approval of the Board, the Company and Brookfield Renewable and certain of their affiliates entered into a definitive agreement (the “Reorganization Agreement”) for Brookfield Renewable to, among other things, acquire all of the shares of Common Stock, other than the 62% currently owned by Brookfield Renewable and its affiliates (the transactions contemplated by the Reorganization Agreement, the “Transactions”). Upon the consummation of the Transactions, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions, will be converted into the right to receive, at each TerraForm Power shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. As provided by the Brookfield Proposal, the adoption of the Plan of Merger (as defined in the Reorganization Agreement) and the approval of the Reorganization Agreement and the consummation of the transactions contemplated thereby is subject to the non-waivable approval of TerraForm Power’s shareholders representing a majority of the outstanding shares of Common Stock not owned by Brookfield Renewable and its affiliates and the consummation of the transactions contemplated by the Reorganization Agreement are subject to customary closing conditions, including receipt of certain regulatory approval. As of the date of this Annual Report, Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

The following table reflects the changes in the Company’s shares of Common Stock outstanding during the years ended December 31, 2019 and 2018:

	As of December 31,
(In thousands)	2019		2018
Balance as of January 1	$	209,142	$	148,086
Issuance of Common Stock in public offering1	14,907		—
Issuance of Common Stock to affiliate2,3	2,982		61,056
Net shares issued under equity incentive plan	13		—
Less: Repurchases of Common Stock4	(543)		—
Balance as of December 31	$	226,501	$	209,142

———

(1)On October 8, 2019, the Company completed an underwritten registered public offering of 14,907,573 shares of Common Stock at a price of $16.77 per share for a total consideration of $250.0 million, not including transaction costs.

(2)On October 8, 2019, concurrently with the public offering described above, the Company completed a private placement of 2,981,514 shares of Common Stock at a price of $16.77 per share to an affiliate of Brookfield for a total consideration of $50.0 million, not including transaction costs.

(3)On June 11, 2018, the Company completed a private placement of 60,975,609 shares of the Company’s Common Stock with affiliates of Brookfield at a price of $10.66 per share for a total consideration of $650.0 million. The proceeds of the offering were used to pay a portion of the purchase price of the Tendered Shares of Saeta. On August 3, 2018, the Company issued 80,084 shares of Common Stock to an affiliate of Brookfield in connection with the net losses incurred, such as out-of-pocket losses, damages, costs, fees and expenses, in connection with the obtainment of a final resolution of a certain litigation matter.

(4)During the fourth quarter of 2019, the Company repurchased a total of 543,265 shares of Common Stock at a total cost of $8.4 million and recorded within Treasury Stock on the consolidated balance sheets.

Merger Consummation and SunEdison Settlement Agreement

As discussed in Note 1. Nature of Operations and Organization, on October 16, 2017, pursuant to the Merger Agreement, Merger Sub merged with and into TerraForm Power, with TerraForm Power continuing as the surviving corporation in the Merger. Immediately following the consummation of the Merger, there were 148,086,027 Class A shares of TerraForm Power outstanding, which excludes 138,402 Class A shares that were issued and held in treasury to pay applicable employee tax withholdings for RSUs held by employees that vested upon the consummation of the Merger. As a result of the Merger, Orion Holdings acquired 51% of TerraForm Power’s outstanding Class A shares.

Prior to the consummation of the Merger, SunEdison was the indirect holder of 100% of the shares of Class B common stock of TerraForm Power and held approximately 83.9% of the combined total voting power of the holders of TerraForm Power’s Class A Common Stock and Class B common stock. As contemplated by the Merger Agreement and in satisfaction of its obligations under the Settlement Agreement, SunEdison exchanged, effective immediately prior to the effective time of the Merger, all of the Class B units of Terra LLC held by it or any of its controlled affiliates for 48,202,310 Class A shares of TerraForm Power. Following completion of this exchange, all of the issued and outstanding shares of Class B common stock of TerraForm Power were automatically redeemed and retired. Pursuant to the Settlement Agreement, immediately following this exchange, the Company issued to SunEdison additional Class A shares such that immediately prior

to the effective time of the Merger, SunEdison and certain of its affiliates held an aggregate number of Class A shares equal to 36.9% of TerraForm Power’s fully diluted share count (which was subject to proration based on the Merger consideration election results as discussed below). As a result of the Merger closing, TerraForm Power is no longer a controlled affiliate of SunEdison and is now a controlled affiliate of Brookfield.

At the effective time of the Merger, each share of Common Stock of TerraForm Power issued and outstanding immediately prior to the effective time of the Merger, except for certain excluded shares, was converted into the right to, at the holder’s election and subject to proration as described below, either (i) receive $9.52 per Class A Share, in cash, without interest (the “Per Share Cash Consideration”) or (ii) retain one share of Common Stock, par value $0.01 per share, of the surviving corporation (the “Per Share Stock Consideration,” and, together with the Per Share Cash Consideration, without duplication, the “Per Share Merger Consideration”). Issued and outstanding shares included shares issued in connection with the SunEdison Settlement Agreement as more fully described above and shares underlying outstanding RSUs of the Company under the Company’s 2014 Second Amended and Restated Long-Term Incentive Plan (the “2014 LTIP”). At the effective time of the Merger, any vesting conditions applicable to any Company RSU outstanding immediately prior to the effective time of the Merger under the 2014 LTIP were automatically and without any required action on the part of the holder, deemed to be satisfied in full, and such Company RSU was canceled and converted into the right to receive the Per Share Merger Consideration, including the election of the Per Share Stock Consideration or the Per Share Cash Consideration in respect of each share (in the case of RSUs subject to performance conditions, with such conditions deemed satisfied at “target” levels), less any tax withholdings. The Per Share Stock Consideration was subject to proration in the event that the aggregate number of Class A Shares for which an election to receive the Per Share Stock Consideration exceeded 49% of the TerraForm Power fully diluted share count (the “Maximum Stock Consideration Shares”). Additionally, the Per Share Cash Consideration was subject to proration in the event that the aggregate number of Class A shares for which an election to receive the Per Share Cash Consideration exceeded the TerraForm Power fully diluted share count minus (i) the Maximum Stock Consideration Shares, (ii) any Class A shares currently held by affiliates of Brookfield, and (iii) any shares for which the holders seek appraisal under Delaware law. Based on the results of the consideration election, the elections of the Per Share Stock Consideration were oversubscribed and the proration ratio was 62.6%, which meant that stockholders electing to receive 100% of their merger consideration in stock retained 62.6% of their Class A shares in the Merger and received cash consideration in respect of 37.4% of their shares.

On October 16, 2017, in connection with the consummation of the Merger, the Company entered into a registration rights agreement (the “SunEdison Registration Rights Agreement”) with SunEdison, SunEdison Holdings Corporation (“SHC”) and SUNE ML 1, LLC (“SML1”). The SunEdison Registration Rights Agreement governed the rights of SunEdison, SHC, SML1 and certain permitted assigns with respect to the registration for resale of Class A shares held by them immediately following the Merger. The Company registered these shares in December of 2017, and these shares were distributed by SunEdison, Inc., SHC and SML1 to certain creditors under the plan of reorganization in connection with SunEdison’s emergence from bankruptcy in December of 2017. 

Upon the consummation of the Merger, TerraForm Power’s certificate of incorporation was amended and restated to include 100,000,000 authorized shares of preferred stock, par value $0.01 per share, and 1,200,000,000 authorized shares of Common Stock, par value $0.01 per share. There were no other authorized classes of shares, and the Company did not have any issued shares of preferred stock as of December 31, 2019, 2018 and 2017.

2019 Public Offering and Concurrent Private Placement of Common Stock to an Affiliate

On October 8, 2019, the Company completed an underwritten registered public offering of 14,907,573 shares of Common Stock at a price of $16.77 per share (the “Public Offering”), for a total consideration of $250.0 million, not including transaction costs. In connection with the Public Offering, the Company entered into an underwriting agreement, dated October 3, 2019 among the Company, Terra LLC and RBC Capital Markets, LLC, as the underwriter.

Concurrent with the Public Offering, on October 8, 2019, the Company completed a private placement of 2,981,514 shares of Common Stock at a price of $16.77 per share (the “2019 Private Placement”), to BBHC Orion Holdco L.P., an affiliate of Brookfield (the “2019 Private Placement Purchaser”), for a total consideration of $50.0 million, not including transaction costs. No underwriting discounts or commissions were paid with respect to the 2019 Private Placement. In connection with the 2019 Private Placement, the Company entered into a stock purchase agreement, dated October 8, 2019, with the 2019 Private Placement Purchaser. The Common Stock issued in the 2019 Private Placement were not registered with the SEC, in reliance on Section 4(a)(2) of the Securities Act and the acknowledgment of the 2018 Private Placement Purchaser that it is an “accredited investor” within the meaning of Rule 501(a) of Regulation D of the Securities Act or a “qualified institutional buyer” under Rule 144A of the Securities Act. Following the Public Offering and the 2019 Private Placement, as of December 31, 2019, affiliates of Brookfield held approximately 62% of the Company’s Common Stock.

The proceeds of the Public Offering and 2019 Private Placement were used to repay the amounts due under the Revolver and for general corporate purposes.

2018 Private Placement of Common Stock to Affiliates

On June 11, 2018, the Company completed a private placement of 60,975,609 shares of Common Stock at a price of $10.66 per share (the “2018 Private Placement”), to Orion Holdings and BBHC Orion Holdco L.P. (together, the “2018 Private Placement Purchasers”) for a total consideration of approximately $650.0 million, not including transaction costs. No underwriting discounts or commissions were paid with respect to the 2018 Private Placement. In connection with the 2018 Private Placement, the Company entered into a stock purchase agreement, dated June 11, 2018, with the 2018 Private Placement Purchasers. The Common Stock issued in the 2018 Private Placement were not registered with the SEC, in reliance on Section 4(a)(2) of the Securities Act and the acknowledgment of each of the 2018 Private Placement Purchasers that it is an “accredited investor” within the meaning of Rule 501(a) of Regulation D of the Securities Act or a “qualified institutional buyer” under Rule 144A of the Securities Act. Immediately upon completion of the 2018 Private Placement, affiliates of Brookfield held approximately 65% of TerraForm Power’s Common Stock as of the date thereof.

The proceeds of the 2018 Private Placement were used by the Company to pay a portion of the purchase price of the Tendered Shares of Saeta. The purchase of $650 million of TerraForm Power’s Common Stock by the 2018 Private Placement Purchasers was made pursuant to a support agreement that the Company had entered into with Brookfield, dated February 6, 2018, and amended on May 28, 2018, at the previously agreed backstop price of $10.66 per share.

2018 Issuance of Common Stock upon Final Resolution of Chamblee Class Action

On August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Common Stock to Orion Holdings in connection with the net losses incurred as a result of the final resolution of a securities class action under federal securities laws (the “Chamblee Class Action”). The net losses for the Chamblee Class Action include the $1.1 million contributed by the Company to the settlement but do not include the $13.6 million contributed by the Company’s insurers and certain attorneys’ fees that TerraForm Global reimbursed to the Company pursuant to the insurance allocation arrangements entered into with the Company in 2017.

Cash Distributions

The following table presents the cash distributions declared and/or paid on Common Stock during the years ended December 31, 2019, 2018 and 2017:

	Type	Distributions per Share		Declaration Date	Record Date	Payment Date
2019:
First Quarter	Ordinary	$	0.2014	March 13, 2019	March 24, 2019	March 29, 2019
Second Quarter	Ordinary	0.2014		May 8, 2019	June 3, 2019	June 17, 2019
Third Quarter	Ordinary	0.2014		August 8, 2019	September 3, 2019	September 17, 2019
Fourth Quarter	Ordinary	0.2014		November 6, 2019	December 2, 2019	December 16, 2019
2018:
First Quarter	Ordinary	$	0.19	February 6, 2018	February 28, 2018	March 30, 2018
Second Quarter	Ordinary	0.19		April 30, 2018	June 1, 2018	June 15, 2018
Third Quarter	Ordinary	0.19		August 13, 2018	September 1, 2018	September 15, 2018
Fourth Quarter	Ordinary	0.19		November 8, 2018	December 3, 2018	December 17, 2018
2017:
Fourth Quarter	Special1	1.94		October 6, 2017	October 16, 2017	October 17, 2017

———

(1)On October 6, 2017, the Board declared the payment of a special cash distribution to holders of record immediately prior to the effective time of the Merger in the amount of $1.94 per fully diluted share, which included the Company’s issued and outstanding Class A shares, Class A shares issued to SunEdison pursuant to the Settlement Agreement (more fully described above) and Class A shares underlying outstanding RSUs of the Company under the 2014 LTIP.

Share Repurchase Program

On July 25, 2019, the Board of the Company authorized the renewal of the Company’s share repurchase program through August 4, 2020. Under the share repurchase program, the Company may repurchase up to 5% of the Company’s Common Stock outstanding as of July 25, 2019. The timing and the amount of any repurchases of Common Stock will be determined by the Company’s management based on its evaluation of market conditions and other factors. Repurchases of Common Stock may be made under a Rule 10b5-1 plan, which would permit Common Stock to be repurchased when the Company might otherwise be precluded from doing so under insider trading laws, open market purchases, privately-negotiated transactions, block purchases or otherwise in accordance with applicable federal securities laws, including Rule 10b-18 under the Exchange Act. The program may be suspended or discontinued at any time and does not obligate the Company to purchase any minimum number of stock. Any repurchased Common Stock will be held by the Company as treasury shares. The Company expects to fund any repurchases from the available liquidity.

During the fourth quarter of 2019, the Company repurchased 543,265 shares at a total cost of $8.4 million and recorded within Treasury Stock on the consolidated balance sheets. No shares were repurchased by the Company during the year ended December 31, 2018.

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Derivatives

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

As part of its risk management strategy, the Company entered into derivative instruments which include interest rate swaps, foreign currency contracts and commodity contracts to mitigate interest rate, foreign currency and commodity price exposures. If the Company elects to do so and if the instrument meets the criteria specified in ASC 815, Derivatives and Hedging, the Company designates its derivative instruments as either cash flow hedges or net investment hedges. The Company enters into interest rate swap agreements in order to hedge the variability the of expected future cash interest payments. Foreign currency contracts are used to reduce risks arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of these practices is to minimize the impact of foreign currency fluctuations on operating results. The Company also enters into commodity contracts to hedge price variability inherent in energy sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot energy prices and stabilize estimated revenue streams. The Company does not use derivative instruments for trading or speculative purposes.

As of December 31, 2019 and 2018, the fair values of the following derivative instruments were included in the respective balance sheet captions indicated below:

	Fair Value of Derivative Instruments1
	Derivatives Designated as Hedging Instruments						Derivatives Not Designated as Hedging Instruments
(In thousands)	Interest Rate Swaps		Foreign Currency Contracts		Commodity Contracts		Interest Rate Swaps		Foreign Currency Contracts		Commodity Contracts		Gross Derivatives		Counterparty Netting2		Net Derivatives
As of December 31, 2019
Derivative assets, current	$	—	$	349	$	1,040	$	—	$	8,092	$	7,279	$	16,760	$	(941)	$	15,819
Derivative assets	809		24		33,269		—		504		23,583		58,189		(472)		57,717
Total assets	$	809	$	373	$	34,309	$	—	$	8,596	$	30,862	$	74,949	$	(1,413)	$	73,536
Derivative liabilities, current	$	12,046	$	631	$	—	$	21,923	$	310	$	—	$	34,910	$	(941)	$	33,969
Derivative liabilities	41,605		315		—		59,412		534		—		101,866		(472)		101,394
Total liabilities	$	53,651	$	946	$	—	$	81,335	$	844	$	—	$	136,776	$	(1,413)	$	135,363
As of December 31, 2018
Derivative assets, current	$	1,478	$	605	$	18	$	—	$	3,344	$	9,783	$	15,228	$	(857)	$	14,371
Derivative assets	5,818		2,060		42,666		—		647		40,137		91,328		(344)		90,984
Total assets	$	7,296	$	2,665	$	42,684	$	—	$	3,991	$	49,920	$	106,556	$	(1,201)	$	105,355
Derivative liabilities, current	$	465	$	—	$	—	$	34,267	$	1,684	$	—	$	36,416	$	(857)	$	35,559
Derivative liabilities	3,334		1,437		—		88,034		1,387		—		94,192		(344)		93,848
Total liabilities	$	3,799	$	1,437	$	—	$	122,301	$	3,071	$	—	$	130,608	$	(1,201)	$	129,407

———

(1)Fair value amounts are shown before the effects of counterparty netting adjustments.

(2)Represents the netting of derivative exposures covered by qualifying master netting arrangements.

As of December 31, 2019 and December 31, 2018, the Company had posted letters of credit in the amount of $15.0 million, as collateral related to certain commodity contracts. Certain derivative contracts contain provisions providing the counterparties a lien on specific assets as collateral. There was no cash collateral received or pledged as of December 31, 2019 and December 31, 2018 related to the Company’s derivative transactions.

The Company elected to present all derivative assets and liabilities on a net basis on the consolidated balance sheets as a right to set-off exists. The Company enters into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements with its counterparties. An ISDA Master Agreement is an agreement that can govern multiple derivative transactions between two counterparties that typically provides for the net settlement of all, or a specified group, of these derivative transactions through a single payment, and in a single currency, as applicable. A right to set-off typically exists when the Company has a legally enforceable ISDA Master Agreement. No amounts were netted for commodity contracts as of December 31, 2019 or 2018 as each of the commodity contracts were in a gain position.

The following table presents the notional amounts of derivative instruments as of December 31, 2019 and 2018:

	December 31,
(In thousands)	2019	2018
Derivatives designated as hedging instruments:
Cash flow hedges:
Interest rate swaps (USD)	441,628	357,797
Interest rate swaps (CAD)	138,575	147,522
Interest rate swaps (EUR)	310,721	—
Commodity contracts (MWhs)	5,360	6,030
Net investment hedges:
Foreign currency contracts (CAD)	94,100	81,600
Foreign currency contracts (EUR)	199,750	320,000
Derivatives not designated as hedging instruments:
Interest rate swaps (USD)	11,399	12,326
Interest rate swaps (EUR)1	745,719	1,044,253
Foreign currency option contracts (EUR)2	625,200	—
Foreign currency forward contracts (EUR)2	118,550	640,200
Commodity contracts (MWhs)	7,610	8,707

————

(1)Represents the notional amount of the interest rate swaps at Saeta to economically hedge the interest rate payments on non-recourse debt. The Company did not designate these derivatives as hedging instruments per ASC 815 as of the respective balance sheet dates.

(2)Represents the notional amount of foreign currency contracts used to economically hedge portions of the Company’s foreign exchange risk associated with Euro-denominated intercompany loans. The Company did not designate these derivatives as hedging instruments per ASC 815 as of December 31, 2019 and December 31, 2018.

Gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018 and 2017 consisted of the following:

	Location of Loss (Gain) in the Statements of Operations	Year Ended December 31,
(In thousands)		2019		2018		2017
Interest rate swaps	Interest expense, net	$	25,790	$	2,565	$	3,161
Foreign currency contracts	Gain on foreign currency exchange, net	(27,233)		(34,714)		966
Commodity contracts	Operating revenues, net	479		3,209		(5,117)

During the second quarter of 2018, the Company discontinued hedge accounting for a certain long-dated commodity contract as it was no longer considered highly effective in offsetting the cash flows associated with the underlying risk being hedged. Long-term electricity prices in the related market declined significantly during the second quarter of 2018, causing the option component of the derivative contract to have an intrinsic value which negatively impacted the effectiveness assessment of the hedge relationship. Hedge accounting was prospectively discontinued effective April 1, 2018, with changes in fair value recorded in earnings. The gains in AOCI as of March 31, 2018 amounted to $44.3 million and $5.7 million of which were recorded in earnings during the three quarters following the discontinuation of hedge accounting. The balance of the accumulated gains deferred in AOCI as of December 31, 2019 was $30.9 million will be amortized through earnings over the term of the contract, which expires in 2023, of which $7.7 million will be amortized within the next 12 months.

As discussed in Note 3. Acquisitions and Divestitures, the Company consummated the sale of the U.K. Portfolio on May 11, 2017. As part of the sale agreement, Vortex Solar UK Limited assumed the debt and the associated interest rate swaps. As of the date of the sale, the remaining loss in AOCI of $0.4 million was reclassified into interest expense, net, and the fair value of the interest rate swap liability of $23.4 million is reflected within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017. The interest expense amount reflected in the table above for the year ended December 31, 2017 primarily pertains to these interest rate swaps.

Gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018 and 2017 consisted of the following:

	Year Ended December 31,
Derivatives in Cash Flow and Net Investment Hedging Relationships	Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes1						Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach2
(In thousands)	2019		2018		2017		2019		2018		2017
Interest rate swaps	$	(33,503)	$	1,034	$	(396)	$	—	$	—	$	—
Foreign currency contracts	13,904		11,169		—		—		—		—
Commodity derivative contracts	(8,920)		(3,163)		18,008		—		452		—
Total	$	(28,519)	$	9,040	$	17,612	$	—	$	452	$	—

	Year Ended December 31,
Location of Amount Reclassified from AOCI into Income	(Gain) Loss Included in the Assessment of Effectiveness Reclassified from AOCI into Income3						(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings
	2019		2018		2017		2019		2018		2017
Interest expense, net	$	1,896	$	1,307	$	5,507	$	—	$	—	$	(1,270)
Gain on foreign currency exchange, net	—		—		—		—		—		—
Operating revenues, net	3,371		(1,804)		(7,754)		—		—		(2,923)
Total	$	5,267	$	(497)	$	(2,247)	$	—	$	—	$	(4,193)

———

(1)Net of $(1.0) million, $3.6 million, and $(0.1) million tax (benefit) expense attributed to interest rate swaps during the years ended December 31, 2019, 2018, and 2017, respectively. Net of $3.9 million tax expense attributed to foreign currency contracts designated as net investment hedges during the year ended December 31, 2018. There were no taxes attributed to foreign currency contracts during the years ended December 31, 2019 and 2017. Net of $2.0 million and $2.5 million tax expense attributed to commodity contracts during the years ended December 31, 2018, 2017, respectively. There were no taxes attributed to commodity contracts during the year ended December 31, 2019.

(2)No tax expense or benefit was recorded for the year ended December 31, 2019. Net of tax expense of $0.3 million for the year ended December 31, 2018.

(3)No tax expense or benefit was recorded for the year ended December 31, 2019. Net of tax benefit of $0.7 million and $1.1 million attributed to interest rate swaps for the years ended December 31, 2018 and 2017, respectively. Net of tax benefit of $2.4 million and $1.5 million attributed to commodity contracts during the years ended December 31, 2018 and 2017, respectively.

Derivatives Designated as Hedging Instruments

Interest Rate Swaps

The Company has interest rate swap agreements to hedge certain variable rate non-recourse debt. These interest rate swaps qualify for hedge accounting and were 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. The change in the fair value of the components included in the effectiveness assessment of these derivatives is initially reported in AOCI and subsequently reclassified to earnings in the periods when the hedged transactions affect earnings (the payment of interest). The amounts deferred in AOCI and reclassified into earnings during the years ended December 31, 2019, 2018 and 2017 related to these interest rate swaps are provided in the tables above. The loss expected to be reclassified into earnings over the next twelve months is approximately $6.9 million. The maximum term of outstanding interest rate swaps designated as hedging instruments is 19 years.

Foreign Currency Forward Contracts

The Company uses foreign currency forward contracts to hedge portions of its net investment positions in certain subsidiaries with Euro (“€”) and Canadian dollar (“C$”) functional currencies and to manage its foreign exchange risk. For instruments that are designated and qualify as hedges of net investment in foreign operations, the effective portion of the net gains or losses attributable to changes in exchange rates are recorded in foreign currency translation adjustments within AOCI.

The recognition in earnings of amounts previously recorded in AOCI is limited to circumstances such as complete or substantial liquidation of the net investment in the hedged foreign operation. 

Cash flows from derivative instruments designated as net investment hedges are classified as investing activities in the consolidated statements of cash flows.

As of December 31, 2019, the total notional amount of foreign currency forward contracts designated as net investment hedges was €200 million and C$94 million. The maturity dates of these derivative instruments designated as net investment hedges range from 3 months to 33 months. As of December 31, 2018, the total notional amount of foreign currency forward contracts designated as net investment hedges was €320 million and C$81.6 million. The maturity dates of these derivative instruments designated as net investment hedges range from 3 months to 2 years. There were no foreign currency forward contracts designated as net investment hedges as of December 31, 2017.

Commodity Contracts

The Company has two long-dated physically delivered commodity contracts that hedge variability in cash flows associated with the sales of power from certain wind renewable energy facilities located in Texas. One of these commodity contract qualifies for hedge accounting and is designated as a cash flow hedge. The change in the fair value of the components included in the effectiveness assessment of this derivative is initially reported in AOCI and subsequently reclassified to earnings in the periods when the hedged transactions affect earnings (the sale of electricity). The amounts deferred in AOCI and reclassified into earnings during the years ended December 31, 2019, 2018 and 2017 related to these commodity contracts are provided in the tables above. The gain expected to be reclassified into earnings over the next twelve months is approximately $1.6 million. The maximum term of the outstanding commodity contract designated as a hedging instrument is 8 years.

Derivatives Not Designated as Hedging Instruments

Interest Rate Swaps

The Company has interest rate swap agreements that economically hedge the cash flows for non-recourse debt. These interest rate swaps pay a fixed rate and the counterparties to the agreements pay a variable interest rate. The changes in fair value are recorded in interest expense, net in the consolidated statements of operations as these derivatives are not accounted for under hedge accounting.

Foreign Currency Contracts

The Company has foreign currency forward and option contracts that economically hedge its exposure to foreign currency fluctuations. As these hedges are not accounted for under hedge accounting, the changes in fair value are recorded in loss (gain) on foreign currency exchange, net in the consolidated statements of operations.

Commodity Contracts

The Company has commodity contracts that to economically hedge commodity price variability inherent in certain electricity sales arrangements. If the Company sells electricity to an independent system operator market and there is no PPA available, it may enter into a commodity contract to hedge all or a portion of their estimated revenue stream. These commodity contracts require periodic settlements in which the Company receives a fixed-price based on specified quantities of electricity and pays the counterparty a variable market price based on the same specified quantity of electricity. As these derivatives are not accounted for under hedge accounting, the changes in fair value are recorded in operating revenues, net in the consolidated statements of operations.

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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Components of Lease Expense and Supplemental Cash Flow Information

The components of lease expense were as follows:

(In thousands)	Year Ended December 31, 2019
Fixed operating lease cost	$	21,619
Variable operating lease cost1	5,884
Total operating lease cost	$	27,503

———

(1)Primarily related to production-based variable inputs and adjustments for inflation.

Supplemental cash flow information related to the Company’s leases was as follows:

(In thousands)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases1	$	16,485

———

(1)Right-of-use assets, excluding the effect of acquisitions, obtained in exchange for lease obligations during the year ended December 31, 2019, were not material.

Supplemental Balance Sheet Information

Supplemental balance sheet information related to the Company’s leases was as follows:

(In thousands, except lease term and discount rate)	As of December 31, 2019
Operating leases:
Right-of-use assets	$	288,321
Accounts payable, accrued expenses and other current liabilities	18,138
Operating lease obligations, less current portion	272,894
Total operating lease liabilities	$	291,032
Weighted Average Remaining Lease Term:
Operating leases	17.6
Weighted Average Discount Rate:
Operating leases	4.8		%

Maturities of Operating Lease Liabilities

The maturities of the Company’s operating lease liabilities by fiscal year were as follows:

(In thousands)
2020	$	21,921
2021	21,828
2022	22,046
2023	22,220
2024	22,424
Thereafter	319,532
Total lease payments	429,971
Less: Imputed interest	(138,939)
Total	$	291,032

Schedule of Future Minimum Rental Payments for Operating Leases

The following table summarizes the Company’s future commitments under operating leases as of December 31, 2018:

(In thousands)	2019		2020		2021		2022		2023		Thereafter		Total
Rent	$	20,002	$	20,005	$	20,241	$	20,410	$	20,577	$	331,425	$	432,660

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Concentration Of Credit Risk - Major Financial Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Cash and cash equivalents	$ 237,480	$ 248,524	$ 128,087
Accounts receivable, net	167,865	145,161
Derivative assets	73,536	105,355
Total	10,058,636	9,330,354	$ 6,387,021
Financial Assets
Concentration Risk [Line Items]
Cash and cash equivalents	349,500	392,809
Accounts receivable, net	167,865	145,161
Derivative assets	73,536	105,355
Total	$ 590,901	$ 643,325

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(Loss) Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Basic and diluted (loss) earnings per share:
Net (loss) income attributable to Class A common stockholders	$ (81,625)	$ (54,837)	$ (3,595)	$ (8,627)	$ (15,489)	$ (33,590)	$ (21,337)	$ 82,796	$ (148,684)	$ 12,380	$ (160,154)
Less: accretion of redeemable non-controlling interest									0	0	(6,729)
Less: cash distributions to Class A shares and participating RSAs									0	0	(285,497)
Undistributed income (loss) attributable to Class A shares									$ (148,684)	$ 12,380	$ (452,380)
Weighted-average basic and diluted Class A shares outstanding (in shares)	217,608,000	209,155,000	209,142,000	209,142,000					213,275,000	182,239,000	103,866,000
Distributed earnings per share (usd per share)									$ 0	$ 0	$ 2.75
Undistributed (loss) earnings per share (usd per share)									(0.70)	0.07	(4.36)
Basic and diluted (loss) earnings per share (usd per share)	$ (0.38)	$ (0.26)	$ (0.02)	$ (0.04)	$ (0.07)	$ (0.16)	$ (0.13)	$ 0.56	$ (0.70)	$ 0.07	$ (1.61)
Restricted Stock Units (RSUs)
Basic and diluted (loss) earnings per share:
Antidilutive shares excluded from computation of earnings per share (in shares)									191,936

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

As of December 31, 2019 and 2018, the fair values of the following derivative instruments were included in the respective balance sheet captions indicated below:

	Fair Value of Derivative Instruments1
	Derivatives Designated as Hedging Instruments						Derivatives Not Designated as Hedging Instruments
(In thousands)	Interest Rate Swaps		Foreign Currency Contracts		Commodity Contracts		Interest Rate Swaps		Foreign Currency Contracts		Commodity Contracts		Gross Derivatives		Counterparty Netting2		Net Derivatives
As of December 31, 2019
Derivative assets, current	$	—	$	349	$	1,040	$	—	$	8,092	$	7,279	$	16,760	$	(941)	$	15,819
Derivative assets	809		24		33,269		—		504		23,583		58,189		(472)		57,717
Total assets	$	809	$	373	$	34,309	$	—	$	8,596	$	30,862	$	74,949	$	(1,413)	$	73,536
Derivative liabilities, current	$	12,046	$	631	$	—	$	21,923	$	310	$	—	$	34,910	$	(941)	$	33,969
Derivative liabilities	41,605		315		—		59,412		534		—		101,866		(472)		101,394
Total liabilities	$	53,651	$	946	$	—	$	81,335	$	844	$	—	$	136,776	$	(1,413)	$	135,363
As of December 31, 2018
Derivative assets, current	$	1,478	$	605	$	18	$	—	$	3,344	$	9,783	$	15,228	$	(857)	$	14,371
Derivative assets	5,818		2,060		42,666		—		647		40,137		91,328		(344)		90,984
Total assets	$	7,296	$	2,665	$	42,684	$	—	$	3,991	$	49,920	$	106,556	$	(1,201)	$	105,355
Derivative liabilities, current	$	465	$	—	$	—	$	34,267	$	1,684	$	—	$	36,416	$	(857)	$	35,559
Derivative liabilities	3,334		1,437		—		88,034		1,387		—		94,192		(344)		93,848
Total liabilities	$	3,799	$	1,437	$	—	$	122,301	$	3,071	$	—	$	130,608	$	(1,201)	$	129,407

———

(1)Fair value amounts are shown before the effects of counterparty netting adjustments.

(2)Represents the netting of derivative exposures covered by qualifying master netting arrangements.

Schedule of Notional Amounts of Outstanding Derivative Positions

The following table presents the notional amounts of derivative instruments as of December 31, 2019 and 2018:

	December 31,
(In thousands)	2019	2018
Derivatives designated as hedging instruments:
Cash flow hedges:
Interest rate swaps (USD)	441,628	357,797
Interest rate swaps (CAD)	138,575	147,522
Interest rate swaps (EUR)	310,721	—
Commodity contracts (MWhs)	5,360	6,030
Net investment hedges:
Foreign currency contracts (CAD)	94,100	81,600
Foreign currency contracts (EUR)	199,750	320,000
Derivatives not designated as hedging instruments:
Interest rate swaps (USD)	11,399	12,326
Interest rate swaps (EUR)1	745,719	1,044,253
Foreign currency option contracts (EUR)2	625,200	—
Foreign currency forward contracts (EUR)2	118,550	640,200
Commodity contracts (MWhs)	7,610	8,707

————

(1)Represents the notional amount of the interest rate swaps at Saeta to economically hedge the interest rate payments on non-recourse debt. The Company did not designate these derivatives as hedging instruments per ASC 815 as of the respective balance sheet dates.

(2)Represents the notional amount of foreign currency contracts used to economically hedge portions of the Company’s foreign exchange risk associated with Euro-denominated intercompany loans. The Company did not designate these derivatives as hedging instruments per ASC 815 as of December 31, 2019 and December 31, 2018.

Gain (loss) of Derivative Instruments

Gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018 and 2017 consisted of the following:

	Location of Loss (Gain) in the Statements of Operations	Year Ended December 31,
(In thousands)		2019		2018		2017
Interest rate swaps	Interest expense, net	$	25,790	$	2,565	$	3,161
Foreign currency contracts	Gain on foreign currency exchange, net	(27,233)		(34,714)		966
Commodity contracts	Operating revenues, net	479		3,209		(5,117)

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

Gains and losses on derivatives not designated as hedging instruments for the years ended December 31, 2019, 2018 and 2017 consisted of the following:

	Year Ended December 31,
Derivatives in Cash Flow and Net Investment Hedging Relationships	Gain (Loss) Included in the Assessment of Effectiveness Recognized in OCI, net of taxes1						Gain (Loss) Excluded from the Assessment of Effectiveness Recognized in OCI Using an Amortization Approach2
(In thousands)	2019		2018		2017		2019		2018		2017
Interest rate swaps	$	(33,503)	$	1,034	$	(396)	$	—	$	—	$	—
Foreign currency contracts	13,904		11,169		—		—		—		—
Commodity derivative contracts	(8,920)		(3,163)		18,008		—		452		—
Total	$	(28,519)	$	9,040	$	17,612	$	—	$	452	$	—

	Year Ended December 31,
Location of Amount Reclassified from AOCI into Income	(Gain) Loss Included in the Assessment of Effectiveness Reclassified from AOCI into Income3						(Gain) Loss Excluded from the Assessment of Effectiveness that is Amortized through Earnings
	2019		2018		2017		2019		2018		2017
Interest expense, net	$	1,896	$	1,307	$	5,507	$	—	$	—	$	(1,270)
Gain on foreign currency exchange, net	—		—		—		—		—		—
Operating revenues, net	3,371		(1,804)		(7,754)		—		—		(2,923)
Total	$	5,267	$	(497)	$	(2,247)	$	—	$	—	$	(4,193)

———

(1)Net of $(1.0) million, $3.6 million, and $(0.1) million tax (benefit) expense attributed to interest rate swaps during the years ended December 31, 2019, 2018, and 2017, respectively. Net of $3.9 million tax expense attributed to foreign currency contracts designated as net investment hedges during the year ended December 31, 2018. There were no taxes attributed to foreign currency contracts during the years ended December 31, 2019 and 2017. Net of $2.0 million and $2.5 million tax expense attributed to commodity contracts during the years ended December 31, 2018, 2017, respectively. There were no taxes attributed to commodity contracts during the year ended December 31, 2019.

(2)No tax expense or benefit was recorded for the year ended December 31, 2019. Net of tax expense of $0.3 million for the year ended December 31, 2018.

(3)No tax expense or benefit was recorded for the year ended December 31, 2019. Net of tax benefit of $0.7 million and $1.1 million attributed to interest rate swaps for the years ended December 31, 2018 and 2017, respectively. Net of tax benefit of $2.4 million and $1.5 million attributed to commodity contracts during the years ended December 31, 2018 and 2017, respectively.

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Schedule of Changes in Common Stock Outstanding

The following table reflects the changes in the Company’s shares of Common Stock outstanding during the years ended December 31, 2019 and 2018:

	As of December 31,
(In thousands)	2019		2018
Balance as of January 1	$	209,142	$	148,086
Issuance of Common Stock in public offering1	14,907		—
Issuance of Common Stock to affiliate2,3	2,982		61,056
Net shares issued under equity incentive plan	13		—
Less: Repurchases of Common Stock4	(543)		—
Balance as of December 31	$	226,501	$	209,142

———

(1)On October 8, 2019, the Company completed an underwritten registered public offering of 14,907,573 shares of Common Stock at a price of $16.77 per share for a total consideration of $250.0 million, not including transaction costs.

(2)On October 8, 2019, concurrently with the public offering described above, the Company completed a private placement of 2,981,514 shares of Common Stock at a price of $16.77 per share to an affiliate of Brookfield for a total consideration of $50.0 million, not including transaction costs.

(3)On June 11, 2018, the Company completed a private placement of 60,975,609 shares of the Company’s Common Stock with affiliates of Brookfield at a price of $10.66 per share for a total consideration of $650.0 million. The proceeds of the offering were used to pay a portion of the purchase price of the Tendered Shares of Saeta. On August 3, 2018, the Company issued 80,084 shares of Common Stock to an affiliate of Brookfield in connection with the net losses incurred, such as out-of-pocket losses, damages, costs, fees and expenses, in connection with the obtainment of a final resolution of a certain litigation matter.

(4)During the fourth quarter of 2019, the Company repurchased a total of 543,265 shares of Common Stock at a total cost of $8.4 million and recorded within Treasury Stock on the consolidated balance sheets.

Dividends Declared

The following table presents the cash distributions declared and/or paid on Common Stock during the years ended December 31, 2019, 2018 and 2017:

	Type	Distributions per Share		Declaration Date	Record Date	Payment Date
2019:
First Quarter	Ordinary	$	0.2014	March 13, 2019	March 24, 2019	March 29, 2019
Second Quarter	Ordinary	0.2014		May 8, 2019	June 3, 2019	June 17, 2019
Third Quarter	Ordinary	0.2014		August 8, 2019	September 3, 2019	September 17, 2019
Fourth Quarter	Ordinary	0.2014		November 6, 2019	December 2, 2019	December 16, 2019
2018:
First Quarter	Ordinary	$	0.19	February 6, 2018	February 28, 2018	March 30, 2018
Second Quarter	Ordinary	0.19		April 30, 2018	June 1, 2018	June 15, 2018
Third Quarter	Ordinary	0.19		August 13, 2018	September 1, 2018	September 15, 2018
Fourth Quarter	Ordinary	0.19		November 8, 2018	December 3, 2018	December 17, 2018
2017:
Fourth Quarter	Special1	1.94		October 6, 2017	October 16, 2017	October 17, 2017

———

(1)On October 6, 2017, the Board declared the payment of a special cash distribution to holders of record immediately prior to the effective time of the Merger in the amount of $1.94 per fully diluted share, which included the Company’s issued and outstanding Class A shares, Class A shares issued to SunEdison pursuant to the Settlement Agreement (more fully described above) and Class A shares underlying outstanding RSUs of the Company under the 2014 LTIP.

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Acquisitions and Divestitures - Saeta Acquisition Price Allocation table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Jun. 12, 2019	Dec. 31, 2018	Jun. 12, 2018	Dec. 31, 2017
Business Combination, As Reported
Goodwill	$ 127,952		$ 120,553		$ 0
Total liabilities assumed		$ 2,373,886
Purchase price, net of cash and restricted cash acquired		831,484
Adjustments
Goodwill adjustments	$ 10,196		$ 7,726
Saeta Yield
Business Combination, As Reported
Renewable energy facilities in service		2,245,591		$ 1,993,520
Accounts receivable		91,343		91,343
Intangible assets		744,005		1,034,176
Goodwill		133,301		123,106
Other assets		46,247		43,402
Total assets acquired		3,260,487		3,285,547
Accounts payable, accrued expenses and other current liabilities		91,271		93,032
Long-term debt		1,894,426		1,906,831
Deferred income taxes		160,573		171,373
Asset retirement obligations		67,612		67,706
Derivative liabilities		137,002		137,002
Other liabilities		23,002		23,002
Total liabilities assumed				2,398,946
Redeemable non-controlling Interests		55,117		55,117
Purchase price, net of cash and restricted cash acquired				831,484
Adjustments
Renewable energy facilities in service		252,071
Intangible assets		(290,171)
Goodwill adjustments		10,195
Other assets		2,845
Total assets acquired		(25,060)
Accounts payable, accrued expenses and other current liabilities		(1,761)
Long-term debt, including current portion		(12,405)
Deferred income taxes		(10,800)
Asset retirement obligations		(94)
Total liabilities assumed		(25,060)
Cash and cash equivalents acquired				187,200
Restricted cash acquired				$ 95,100
Saeta Yield | Regulated Solar and Wind
Business Combination, As Reported
Goodwill		103,800
Saeta Yield | Wind
Business Combination, As Reported
Goodwill		$ 29,500

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Long-Term Debt - Debt Maturities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Sep. 25, 2019	Dec. 31, 2018
Maturities of Long-term Debt and Capital Lease Obligations [Abstract]
2020	$ 742,664,000
2021	273,160,000
2022	437,168,000
2023	770,276,000
2024	279,648,000
Thereafter	3,726,020,000
Total	6,228,936,000
Default amount	159,300,000		$ 166,400,000
Deferred financing costs	5,700,000
Bridge Facility
Debt Instrument [Line Items]
Face amount of debt instrument	$ 474,600,000	$ 475,000,000.0
Debt instrument extension term	1 year

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Fair Value of Financial Instruments - Narrative (Details)	Dec. 31, 2019	Dec. 31, 2018
Senior Notes due 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value relative to face	103.40%	93.50%
Senior Notes due 2028
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value relative to face	105.80%	102.50%
Senior Notes Due 2030
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value relative to face	102.20%
Senior Notes due 2025
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value relative to face		89.80%

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Long-Term Debt - Covenants and Cross Defaults (Details) - USD ($)	Dec. 12, 2017	Nov. 08, 2017
Debt Instrument [Line Items]
Debt default threshold for acceleration		$ 75,000,000.0
New Revolver and New Term Loan
Debt Instrument [Line Items]
Debt default threshold for acceleration		$ 75,000,000.0
Debt default acceleration percentage		50.00%
Secured Debt | Senior Notes Due 2023 and 2028
Debt Instrument [Line Items]
Debt default threshold for acceleration	$ 100,000,000.0
Secured Debt | Senior Notes due 2030
Debt Instrument [Line Items]
Debt default threshold for acceleration	$ 140,000,000.0
Secured Debt | Senior Notes
Debt Instrument [Line Items]
Debt default acceleration percentage	25.00%
Debt default threshold for acceleration, percentage	1.50%

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Stockholders' Equity - Narrative (Details) $ / shares in Units, $ in Thousands										3 Months Ended	12 Months Ended
	Mar. 16, 2020	Oct. 08, 2019 USD ($) $ / shares shares	Aug. 03, 2018 USD ($) shares	Jun. 12, 2018	Jun. 11, 2018 USD ($) $ / shares shares	May 28, 2018 USD ($) $ / shares	Oct. 16, 2017 $ / shares shares	Oct. 15, 2017 shares	Aug. 31, 2017 USD ($)	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) shares	Mar. 17, 2020	Jan. 11, 2020	Jul. 25, 2019
Class of Stock [Line Items]
Preferred shares authorized (in shares)							100,000,000			100,000,000	100,000,000
Preferred stock, par value (usd per share) | $ / shares							$ 0.01			$ 0.01	$ 0.01
Common stock, shares authorized (in shares)										1,200,000,000	1,200,000,000	1,200,000,000
Par value (usd per share) | $ / shares										$ 0.01	$ 0.01	$ 0.01
Common stock outstanding (in shares)										226,501,000	226,501,000	209,142,000	148,086,000
Treasury stock (in shares)										1,051,298	1,051,298	500,420
Consideration threshold							49.00%
Proration ratio							62.60%
Consideration elected to receive							100.00%
Percentage of shares retained							62.60%
Percentage of cash consideration received							37.40%
Issuance of common stock (in shares)											14,907,000	0
Proceeds from issuance of common stock | $											$ 298,767	$ 650,000	$ 0
New issuances of common stock (in shares)			80,084								2,982,000	61,056,000
Purchase of treasury stock (in shares)										543,265	543,000	0
Purchase of treasury stock | $										$ 8,400	$ 8,353
Public Offering
Class of Stock [Line Items]
Issuance of common stock (in shares)		14,907,573
Sale of stock, price per share (in usd per share) | $ / shares		$ 16.77
Proceeds from issuance of common stock | $		$ 250,000
Private Placement
Class of Stock [Line Items]
Issuance of common stock (in shares)		2,981,514			60,975,609
Sale of stock, price per share (in usd per share) | $ / shares		$ 16.77			$ 10.66
Proceeds from issuance of common stock | $		$ 50,000			$ 650,000
Share Purchase Agreement
Class of Stock [Line Items]
New issuances of common stock (in shares)					60,975,609
Percentage of ownership after transaction					65.00%
Chamblee Class Action
Class of Stock [Line Items]
Legal fees and expenses | $			$ 1,100
Litigation settlement, portion covered by insurance providers | $			$ 13,600						$ 13,600
Class A Common Stock Issued
Class of Stock [Line Items]
Common stock, shares authorized (in shares)							1,200,000,000
Par value (usd per share) | $ / shares							$ 0.01
Common stock outstanding (in shares)							148,086,027
Treasury stock (in shares)							138,402
Class A Common Stock Issued | Share Repurchase Program, July 25, 2019 Through August 4, 2020
Class of Stock [Line Items]
Authorized repurchase amount of common stock, percentage																5.00%
Class A Common Stock Issued | Chamblee Class Action
Class of Stock [Line Items]
New issuances of common stock (in shares)			80,084
Class A Common Stock Issued | SunEdison
Class of Stock [Line Items]
Exchanged (in shares)							48,202,310	48,202,310
Equity held							36.90%	36.90%
Brookfield Asset Management
Class of Stock [Line Items]
Voting interests acquired							51.00%
Backstop support, offering price per share (usd per share) | $ / shares						$ 10.66
Backstop support agreement amount | $						$ 650,000
TerraForm Power | Class A Common Stock Issued
Class of Stock [Line Items]
Par value (usd per share) | $ / shares							$ 0.01
Cash consideration (usd per share) | $ / shares							$ 9.52
Subsequent Event | Common Stock | TerraForm Power | Brookfield Renewable | Class A Common Stock Issued
Class of Stock [Line Items]
Proposal to acquire shares of Common Stock for consideration of shares equivalent	0.381
TerraForm Power | Class B Common Stock | SunEdison
Class of Stock [Line Items]
Ownership percentage held								100.00%
TerraForm Power | Affiliates of Brookfield
Class of Stock [Line Items]
Ownership percentage held										62.00%	62.00%
TerraForm Power | Affiliates of Brookfield | Private Placement
Class of Stock [Line Items]
Percentage of ownership after transaction		62.00%
TerraForm Power | Affiliates of Brookfield | Share Purchase Agreement
Class of Stock [Line Items]
Percentage of ownership after transaction				65.00%								65.00%
TerraForm Power | SunEdison
Class of Stock [Line Items]
Ownership percentage held								83.90%
TerraForm Power | Subsequent Event | Brookfield Renewable
Class of Stock [Line Items]
Ownership percentage, indirect														30.00%	30.00%

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Acquisition and Divestitures - WGL Purchase Price Allocation (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Sep. 26, 2019	Jun. 12, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Total liabilities assumed			$ 2,373,886
Escrow Deposit	$ 24,831			$ 0
Right-of-use asset	$ 288,321
WGL Acquisition
Business Acquisition [Line Items]
Renewable energy facilities in service		$ 581,717
Intangible assets		168,825
Accounts receivable		13,160
Prepaid expenses and other assets		9,734
Total assets acquired		773,436
Accounts payable, accrued expenses and other current liabilities		6,806
Asset retirement obligations		27,338
Operating lease liabilities		21,663
Other liabilities		7,650
Total liabilities assumed		63,457
Non-controlling interests		3,028
Purchase price, net of cash and restricted cash acquired		706,951
Escrow Deposit		24,831
Purchase price, net of cash and restricted cash acquired		731,782
Right-of-use asset		22,600
Cash and cash equivalents acquired		$ 3,400

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Stock-Based Compensation - Award Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Award
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Beginning (in shares)	0	0	366,195
Vested (in shares)			(366,195)
Ending (in shares)	0	0	0
Weighted-Average Grant-Date Fair Value Per Share
Beginning weighted average grant date fair value ($ per share)	$ 0	$ 0	$ 8.51
Vested ($ per share)			8.51
Ending weighted average grant date fair value ($ per share)	$ 0	$ 0	$ 0
Weighted- Average Exercise Price
Aggregate Intrinsic Value	$ 0	$ 0	$ 0
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Beginning (in shares)	103,300	0	1,622,953
Granted (in shares)	156,550	117,424	523,877
Vested (in shares)	(20,878)		(1,414,857)
Forfeited (in shares)	(47,036)	(14,124)	(731,973)
Ending (in shares)	191,936	103,300	0
Weighted- Average Exercise Price
Beginning weighted average exercise price (in $ per share)	$ 11.15
Granted weighted average exercise price (in $ per share)	12.17
Vested weighted average exercise price ($ per share)	11.15
Forfeited weighted average exercise price ($ per share)	11.64
Ending weighted average exercise price	$ 11.57	$ 11.15
Aggregate Intrinsic Value	$ 2,954,000	$ 1,159,000
Weighted Average Remaining Contractual Life	1 year	2 years

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Stock-based Compensation

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Stock-based Compensation

STOCK-BASED COMPENSATION

In March 2018, the Company implemented its 2018 Amended and Restated Long-Term Incentive Plan (the “2018 LTIP”), which is an equity incentive plan that provides for the award of incentive and nonqualified stock options, restricted stock awards (“RSAs”) and RSUs to employees and directors of the Company. The 2018 LTIP amended and restated the 2014 LTIP. During the years ended December 31, 2017 and 2016, the 2014 LTIP extended to employees and directors who also provided services to the Company’s affiliates, including SunEdison and TerraForm Global during the periods those companies were affiliates of the Company. The 2018 LTIP only applies to employees and directors of the Company. The maximum contractual term of an award is ten years from the date of grant. As of December 31, 2019, an aggregate of 3,734,185 shares of Common Stock were available for issuance under the 2018 LTIP. Upon exercise of stock options or the vesting of RSUs, the Company will issue shares that have been previously authorized to be issued.

Historically, stock-based compensation costs related to equity awards in the Company’s stock were allocated to the Company, SunEdison and TerraForm Global based on the relative percentage of time that the personnel and directors spent providing services to the respective companies. As of January 1, 2017, the Company hired certain former employees of SunEdison who provided dedicated services to the Company. The amount of stock-based compensation expense related to equity awards in the Company’s stock which has been awarded to the Company’s employees was $11.3 million for the years ended December 31, 2017, and is reflected in the consolidated statements of operations within general and administrative expenses. The total amount of stock-based compensation cost related to equity awards in the Company’s stock which has been allocated to SunEdison and TerraForm Global was $3.4 million for the year ended December 31, 2017, and was recognized as a distribution to SunEdison within Net SunEdison investment on the consolidated statements of stockholders’ equity with no impact to the Company’s consolidated statements of operations. Similarly, stock-based compensation costs related to equity awards in the stock of SunEdison and TerraForm Global awarded to employees of the Company were allocated to the Company. The amount of stock-based compensation expense related to equity awards in the stock of SunEdison and TerraForm Global that was allocated to the Company was $5.5 million for the year ended December 31, 2017, and is reflected in the consolidated statements of operations within general and administrative expenses - affiliate and has been treated as an equity contribution from SunEdison within Net SunEdison investment on the consolidated statements of stockholders’ equity. In July of 2017, the Bankruptcy Court approved SunEdison’s plan of reorganization which provided that all unvested equity awards in the stock of SunEdison would be canceled. As a result, all previously unrecognized compensation cost pertaining to unvested equity awards in the stock of SunEdison that were held by the Company’s employees of $2.2 million was allocated to the Company, which is reflected within the stock-based compensation expense amount for the year ended December 31, 2017.

Restricted Stock Awards

RSAs provide the holder with immediate voting rights, but are restricted in all other respects until vested. Upon a termination of employment for any reason, any unvested shares of Common Stock held by the terminated participant will be forfeited. All unvested RSAs are paid and distributions. There were no unvested RSAs as of December 31, 2017 and 2018.

The following table presents information regarding outstanding RSAs as of December 31, 2019, 2018 and 2017. and changes during the year then ended:

	Number of RSAs Outstanding	Weighted-Average Grant-Date Fair Value Per Share		Aggregate Intrinsic Value (in millions)
Balance at January 1, 2017	366,195	$	8.51
Vested	(366,195)	8.51
Balance as of December 31, 2017, 2018 and 2019	—	—		$	—

Restricted Stock Units

The RSUs do not entitle the holders to voting rights and holders of the RSUs do not have any right to receive cash distributions. The following table presents information regarding outstanding RSUs as of December 31, 2019 and 2018 and changes during the year then ended:

(In thousands, except per share data and the number of years)	Number of RSUs Outstanding	Weighted- Average Exercise Price		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Life
Balance at January 1, 2017	1,622,953
Granted	523,877
Vested	(1,414,857)
Forfeited	(731,973)
Balance as of December 31, 2017	—
Granted	117,424
Forfeited	(14,124)
Balance as of December 31, 2018	103,300	$	11.15	$	1,159	2 years
Granted	156,550	12.17
Vested	(20,878)	11.15
Forfeited	(47,036)	11.64
Balance as of December 31, 2019	191,936	11.57		2,954		1 year

The total fair value of RSUs that vested during the years ended December 31, 2019, and 2017, was $0.3 million and $16.7 million, respectively. The weighted average fair value of RSUs on the date of grant during the same periods was $12.17 and $12.22, respectively. No RSUs vested during the year ended December 31, 2018 and the weighted-average fair value on the date of the grant was $11.15 per share. The unrecognized compensation cost related to the RSUs as of December 31, 2019 and 2018, was $1.6 million and $0.9 million, respectively. The vesting schedule of the RSUs awarded in 2019 and 2018 is three years and the Company recognizes the grant-date fair value as a compensation cost on a straight-line basis over the vesting period.

As discussed in Note 1. Nature of Operations and Organization, on October 16, 2017, TerraForm Power consummated the Merger with certain affiliates of Brookfield. Pursuant to the 2014 LTIP, the Merger resulted in a change of control causing all unvested equity awards issued under the plan to vest. As a result, the Company recognized a $7.0 million stock-based compensation charge in the fourth quarter of 2017, which is reflected in the consolidated statements of operations within general and administrative expenses. The Company also recognized a $1.0 million charge related to allocated stock-based compensation costs for equity awards in the stock of TerraForm Global that vested upon the change of control of TerraForm Power. The charge is reflected in the consolidated statements of operations within general and administrative expenses - affiliate.

Time-based RSUs

During the year ended December 31, 2017, the Company awarded 523,877 time-based RSUs to certain employees and executive officers of SunEdison, TerraForm Global and the Company. The weighted average grant-date fair value of these time-based awards during the same periods was $6.4 million which was calculated based on the Company’s closing stock price on

the date of the grant. The vesting schedule of the awarded RSUs ranged from six months to four years, and the Company was recognizing the grant-date fair value as compensation cost on a straight-line basis over the vesting period. These time-based RSUs vested upon the consummation of the Merger. During the year ended December 31, 2019 and 2018, the Company did not award any time-based RSUs.

Stock Options

As of December 31, 2019 and 2018, there were no outstanding stock options and no unrecognized compensation cost in relation to stock options.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTSThe fair values of assets and liabilities are determined using either unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available and using unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available. The Company uses valuation techniques that maximize the use of observable inputs. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. If the inputs into the valuation are not corroborated by market data, in such instances, the valuation for these contracts is established using techniques including the extrapolation from or interpolation between actively traded contracts, as well as the calculation of implied volatilities. When such inputs have a

significant impact on the measurement of fair value, the instrument is categorized as Level 3. The Company regularly evaluates and validates the inputs used to determine the fair value of Level 3 contracts by using pricing services to support the underlying market price of the commodity.

The Company uses a discounted cash flow valuation technique to determine the fair value of its derivative assets and liabilities. The primary inputs in the valuation models for commodity contracts are market observable forward commodity curves, risk-free discount rates, volatilities and, to a lesser degree, credit spreads. The primary inputs into the valuation of interest rate swaps and foreign currency contracts are forward interest rates and foreign currency exchange rates and, to a lesser degree, credit spreads.

Recurring Fair Value Measurements

The following table summarizes the financial instruments measured at fair value on a recurring basis classified in the fair value hierarchy (Level 1, 2 or 3) based on the inputs used for valuation in the consolidated balance sheets:

	As of December 31, 2019								As of December 31, 2018
(In thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	809	$	—	$	809	$	—	$	7,296	$	—	$	7,296
Commodity contracts	—		5,859		59,312		65,171		—		12,952		79,652		92,604
Foreign currency contracts	—		7,556		—		7,556		—		5,455		—		5,455
Total derivative assets	$	—	$	14,224	$	59,312	$	73,536	$	—	$	25,703	$	79,652	$	105,355
Liabilities
Interest rate swaps	$	—	$	134,986	$	—	$	134,986	$	—	$	126,100	$	—	$	126,100
Foreign currency contracts	—		377		—		377		—		3,307		—		3,307
Total derivative liabilities	$	—	$	135,363	$	—	$	135,363	$	—	$	129,407	$	—	$	129,407

The Company’s interest rate swaps, foreign currency contracts and financial commodity contracts are considered Level 2, since all significant inputs are corroborated by market observable data. The Company’s long-term physically settled commodity contracts (see Note 12. Derivatives) are considered Level 3 as they contain significant unobservable inputs. There were no transfers in or out of Level 1, Level 2 and Level 3 during the years ended December 31, 2019 and 2018.

The following table reconciles the changes in the fair value of derivative instruments classified as Level 3 in the fair value hierarchy for the years ended December 31, 2019 and 2018:

	Year Ended December 31,
(In thousands)	2019		2018
Balance as of January 1	$	79,652	$	80,268
Realized and unrealized (losses) gains:
Included in other comprehensive loss	(8,920)		(4,736)
Included in operating revenues, net	(12,441)		6,244
Net settlements	1,021		(2,124)
Balance as of December 31	$	59,312	$	79,652

The significant unobservable inputs used in the valuation of the Company’s commodity contracts classified as Level 3 in the fair value hierarchy as of December 31, 2019 are as follows:

(In thousands, except range)	Fair Value as of December 31, 2019
Transaction Type	Assets		Liabilities		Valuation Technique	Unobservable Inputs as of December 31, 2019
Commodity contracts - power	$	59,312	$	—	Option model	Volatilities	14.2%
							Range
					Discounted cash flow	Forward price (per MWh)	$	6.30	-	$	169.30

The sensitivity of the Company’s fair value measurements to increases (decreases) in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Impact on Fair Value Measurement
Increase (decrease) in forward price	Forward sale	Decrease (increase)
Increase (decrease) in implied volatilities	Purchase option	Increase (decrease)

The Company measures the sensitivity of the fair value of its Level 3 commodity contracts to potential changes in commodity prices using a mark-to-market analysis based on the current forward commodity prices and estimates of the price volatility. An increase in power forward prices will produce a mark-to-market loss, while a decrease in prices will result in a mark-to-market gain. An increase in the estimates of the price volatility will produce a mark-to-market gain, while a decrease in volatility will result in a mark-to-market loss.

Fair Value of Debt

The carrying amount and estimated fair value of the Company’s long-term debt as of December 31, 2019 and 2018 was as follows:

	As of December 31, 2019				As of December 31, 2018
(In thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	6,235,382	$	6,512,188	$	5,761,845	$	5,789,702

The fair value of the Company’s long-term debt, except the corporate-level senior notes, was determined using inputs classified as Level 2 and a discounted cash flow approach using market rates for similar debt instruments. The fair value of the corporate-level senior notes is based on market price information which is classified as a Level 1 input. They are measured using the last available trades at the end of each respective fiscal year. The fair values of the Senior Notes due 2023, Senior Notes due 2028 and Senior Notes due 2030 were 103.4%, 105.8% and 102.2% of face value as of December 31, 2019, respectively. The fair values of the Senior Notes due 2023, Senior Notes due 2025 and Senior Notes due 2028 were 93.5%, 89.8% and 102.5% of face value as of December 31, 2018, respectively.

Nonrecurring Fair Value Measurements

Assets and liabilities that are measured at fair value on a nonrecurring basis relate primarily to renewable energy facilities, goodwill and intangibles, which are remeasured when the derived fair value is below the carrying value on the Company’s consolidated balance sheet. For these assets, the Company does not periodically adjust carrying value to fair value except in the event of impairment. When the impairment has occurred, the Company measures the required charges and adjusts the carrying value as discussed in Note 2. Summary of Significant Accounting Policies. For discussion about the impairment testing of assets and liabilities not measured at fair value on a recurring basis see Note 6. Renewable Energy Facilities and Note 7. Intangible Assets, Net and Goodwill for additional details.

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Related Parties

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Parties

RELATED PARTIES

As discussed in Note 1. Nature of Operations and Organization, the Company is a controlled affiliate of Brookfield. Brookfield held approximately 62% of the voting securities of TerraForm Power’s Common Stock as of December 31, 2019. Certain affiliates of Brookfield hold the outstanding IDRs of Terra LLC held by certain affiliates of Brookfield, and the Company and the Brookfield IDR Holder entered into an amended and restated limited liability company agreement of Terra LLC as discussed below under Brookfield Sponsorship Transaction, which adjusted the distribution thresholds and percentages applicable to the IDRs.

Brookfield Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal from Brookfield Renewable Partners L.P., an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a Special Committee of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into the Reorganization Agreement for Brookfield Renewable to acquire all of the Company's outstanding shares of Common Stock, other than the approximately 62% currently owned by Brookfield Renewable and its affiliates. Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately

prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

Brookfield Sponsorship Transaction

As discussed in Note 1. Nature of Operations and Organization, the Company entered into a suite of agreements with Brookfield and/or certain of its affiliates providing for sponsorship arrangements, as are more fully described below.

Brookfield Master Services Agreement

The Company entered into a master services agreement (the “Brookfield MSA”) with Brookfield and certain affiliates of Brookfield (collectively, the “MSA Providers”) pursuant to which the MSA Providers provide certain management and administrative services to the Company, including the provision of strategic and investment management services. As consideration for the services provided or arranged for by Brookfield and certain of its affiliates pursuant to the Brookfield MSA, the Company pays a base management fee on a quarterly basis that is paid in arrears and calculated as follows:

•for each of the first four quarters following the closing date of the Merger, a fixed component of $2.5 million per quarter (subject to proration for the quarter including the closing date of the Merger) plus 0.3125% of the market capitalization value increase for such quarter;

•for each of the next four quarters, a fixed component of $3.0 million per quarter adjusted annually for inflation plus 0.3125% of the market capitalization value increase for such quarter; and

•thereafter, a fixed component of $3.75 million per quarter adjusted annually for inflation plus 0.3125% of the market capitalization value increase for such quarter.

For purposes of calculating the quarterly payment of the base management fee, the term market capitalization value increase means, for any quarter, the increase in value of the Company’s market capitalization for such quarter, calculated by multiplying the number of outstanding shares of common stock as of the last trading day of such quarter by the difference between (x) the volume-weighted average trading price of a share of common stock for the trading days in such quarter and (y) $9.52. If the difference between (x) and (y) in the market capitalization value increase calculation for a quarter is a negative number, then the market capitalization value increase is deemed to be zero.

Pursuant to the Brookfield MSA, the Company recorded charges of $26.8 million and $14.6 million within General and administrative expenses - affiliate in the consolidated statements of operations for the year ended December 31, 2019 and 2018, respectively. The balance payable under the Brookfield MSA was $8.6 million and $4.2 million in the consolidated balance sheets as of December 31, 2019 and 2018, respectively.

Relationship Agreement

The Company entered into a relationship agreement (the “Relationship Agreement”) with Brookfield, which governs certain aspects of the relationship between Brookfield and the Company. Pursuant to the Relationship Agreement, Brookfield agrees that the Company will serve as the primary vehicle through which Brookfield and certain of its affiliates will own operating wind and solar assets in North America and Western Europe and that Brookfield will provide the Company, subject to certain terms and conditions, with a right of first offer on certain operating wind and solar assets that are located in such countries and developed by persons sponsored by or under the control of Brookfield. The rights of the Company under the Relationship Agreement are subject to certain exceptions and consent rights set out therein. See Item 1A. Risk Factors. Risks Related to our Relationship with Brookfield. The Company did not acquire any renewable energy facilities from Brookfield during the years ended December 31, 2019 and 2018.

Terra LLC Agreement

BRE Delaware, Inc. (the “Brookfield IDR Holder”), an indirect, wholly-owned subsidiary of Brookfield, holds all of the outstanding IDRs of Terra LLC. The Company, Brookfield IDR Holder and TerraForm Power Holdings, Inc. are party to the limited liability company agreement of Terra LLC (as amended from time to time, the “Terra LLC Agreement”). Under the Terra LLC Agreement, IDRs are payable when distributions on Common Stock reach a certain threshold. The IDR threshold for

a first distribution is $0.93 per share of Common Stock and for a second distribution is $1.05 per share of Common Stock. There were no IDR payments made by the Company pursuant to the Terra LLC Agreement during the years ended December 31, 2019 and 2018.

Registration Rights Agreement

The Company entered into a registration rights agreement (the “Registration Rights Agreement”) on October 16, 2017 with Orion Holdings. On June 11, 2018, Orion Holdings, Brookfield BRP Holdings (Canada) Inc. and the Company entered into a Joinder Agreement pursuant to which Brookfield BRP Holdings (Canada) Inc. became a party to the Registration Rights Agreement. On June 29, 2018, a second Joinder Agreement was entered into among Orion Holdings, Brookfield BRP Holdings (Canada) Inc., BBHC Orion Holdco L.P. and the Company pursuant to which BBHC Orion Holdco L.P. became a party to the Registration Rights Agreement. The Registration Rights Agreement governs the rights and obligations of the parties thereto with respect to the registration for resale of all or a part of the Class A shares held by Orion Holdings, BBHC Orion Holdco L.P and such other affiliates of Brookfield from time to time to the Registrations Rights Agreement.

Sponsor Line Agreement

On October 16, 2017, the Company entered into the Sponsor Line with Brookfield and one of its affiliates (the “Lenders”). The Sponsor Line establishes a $500.0 million secured revolving credit facility and provides for the Lenders to commit making LIBOR loans to the Company during a period not to exceed three years from the effective date of the Sponsor Line (subject to acceleration for certain specified events). The Company may only use the revolving Sponsor Line to fund all or a portion of certain funded acquisitions or growth capital expenditures. The Sponsor Line terminates, and all obligations thereunder become payable, no later than October 16, 2022. Borrowings under the Sponsor Line bear interest at a rate per annum equal to a LIBOR rate determined by reference to the costs of funds for U.S. dollar deposits for the interest period relevant to such borrowing adjusted for certain additional costs, in each case plus 3.00% per annum. In addition to paying interest on outstanding principal under the Sponsor Line, the Company is required to pay a standby fee of 0.50% per annum in respect of the unutilized commitments thereunder, payable quarterly in arrears. As a consideration for entering into the Sponsor Line credit facility, the Company paid Brookfield an upfront fee of $5.0 million representing 1.00% of the credit facility amount during the year ended December 31, 2017, which is recorded, less the cumulative amortization expense, within other assets in the consolidated balance sheets. The Company is permitted to voluntarily reduce the unutilized portion of the commitment amount and repay outstanding loans under the Sponsor Line at any time without premium or penalty, other than customary “breakage” costs. TerraForm Power’s obligations under the Sponsor Line are secured by first-priority security interests in substantially all assets of TerraForm Power, including 100% of the capital stock of Terra LLC, in each case subject to certain exclusions set forth in the credit documentation governing the Sponsor Line. Under certain circumstances, the Company may be required to prepay amounts outstanding under the Sponsor Line. During the year ended December 31, 2018, the Company made two draws on the Sponsor Line totaling $86.0 million that were used to fund part of the purchase price of the acquisition of Saeta and repaid such amounts in full. As of December 31, 2019, and December 31, 2018, respectively, there were no amounts drawn under the Sponsor Line. Total interest expense, including the amortization of the deferred financing costs incurred on the Sponsor Line for the years ended December 31, 2019, 2018, and 2017, amounted to $4.2 million, $5.2 million, and $0.9 million, respectively.

Governance Agreement

In connection with the consummation of the Merger, the Company entered into a governance agreement (the “Governance Agreement”) with Orion Holdings and any controlled affiliate of Brookfield (other than the Company and its controlled affiliates) that by the terms of the Governance Agreement from time to time becomes a party thereto. The Governance Agreement establishes certain rights and obligations of the Company and controlled affiliates of Brookfield that own voting securities of the Company relating to the governance of the Company and the relationship between such affiliates of Brookfield and the Company and its controlled affiliates. On June 11, 2018, Orion Holdings, Brookfield BRP Holdings (Canada) Inc. and the Company entered into a Joinder Agreement pursuant to which Brookfield BRP Holdings (Canada) Inc. became a party to the Governance Agreement. On June 29, 2018, a second Joinder Agreement was entered into among Orion Holdings, Brookfield BRP Holdings (Canada) Inc., BBHC Orion Holdco L.P. and the Company pursuant to which BBHC Orion Holdco L.P. became a party to the Governance Agreement.

New York Office Lease & Co-tenancy Agreement

In May 2018 and in connection with the relocation of the Company’s corporate headquarters to New York City, the Company entered into a lease for office space and related co-tenancy agreement with affiliates of Brookfield for a ten-year

term. The Company recorded $0.9 million and $0.8 million of charges within general and administrative expenses - affiliate in the consolidated statements of operations during the years ended December 31, 2019 and 2018, respectively.

Amended and Restated Terra LLC Agreement

As discussed above, SunEdison transferred all of the outstanding IDRs of Terra LLC held by SunEdison or certain of its affiliates to Brookfield IDR Holder at the effective time of the Merger, and the Company and Brookfield IDR Holder entered into an amended and restated limited liability company agreement of Terra LLC (as amended from time to time, the “New Terra LLC Agreement”). The New Terra LLC Agreement, among other things, reset the IDR thresholds of Terra LLC to establish a first distribution threshold of $0.93 per share of Common Stock and a second distribution threshold of $1.05 per share of Common Stock. As a result of the New Terra LLC Agreement, amounts distributed from Terra LLC are distributed on a quarterly basis as follows:

•first, to the Company in an amount equal to the Company’s outlays and expenses for such quarter;

•second, to holders of Class A units, until an amount has been distributed to such holders of Class A units that would result, after taking account of all taxes payable by the Company in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Common Stock of $0.93 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Common Stock) if such amount were distributed to all holders of shares of Common Stock;

•third, 15% to the holders of the IDRs and 85% to the holders of Class A units until a further amount has been distributed to holders of Class A units in such quarter that would result, after taking account of all taxes payable by the Company in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Common Stock of an additional $0.12 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Common Stock) if such amount were distributed to all holders of shares of Common Stock; and

•thereafter, 75% to holders of Class A units and 25% to holders of the IDRs.

The Company made no IDR payments during the years ended December 31, 2019 and 2018.

Other Brookfield Transactions and Agreements

2018 Private Placement

As discussed in Note 16. Stockholders' Equity, on June 11, 2018, pursuant to a support agreement between Brookfield and the Company, the Company completed the 2018 Private Placement, whereby affiliates of Brookfield purchased 60,975,609 shares of Common Stock at a price per share of $10.66, representing total consideration of approximately $650.0 million. Immediately upon completion of the 2018 Private Placement, affiliates of Brookfield held approximately 65% of TerraForm Power’s Common Stock as of the date thereof.

2019 Private Placement

As discussed in Note 16. Stockholders’ Equity, concurrent with the Company’s Public Offering on October 8, 2019, the Company completed the 2019 Private Placement, whereby affiliates of Brookfield purchased 2,981,514 shares of Common Stock at a price per share of $16.77, representing total consideration of $50.0 million. Upon completion of the Public Offering and the 2019 Private Placement, as of December 31, 2019, affiliates of Brookfield held approximately 62% of TerraForm Power’s Common Stock.

1Acquisition-related Services

During the year ended December 31, 2019, an affiliate of Brookfield incurred $1.4 million for services and fees payable on behalf of the Company in relation to acquisitions in Spain. These costs primarily represent professional fees for legal, valuation and accounting services.

In connection with bank guarantees issued in support of the Saeta acquisition (Note 3. Acquisitions and Divestitures), Brookfield provided credit support to the Company, and the Company agreed to pay a fee to Brookfield equal to 50% of the savings realized by the Company as a result of Brookfield’s provision of credit support, which amounted to $2.9 million and was paid in the second quarter of 2018. The bank guarantees were canceled following the acquisition of Saeta and no amounts remain outstanding thereunder.

During the year ended December 31, 2018, the Company paid an affiliate of Brookfield $4.0 million for services and fees paid on behalf of the Company by affiliates of Brookfield in relation to the acquisition of Saeta. These costs primarily represent investment banker advisory fees and professional fees for legal and accounting services.

Recovery of Short-swing Profit Claim

During the year ended December 31, 2018, the Company received $3.7 million from Brookfield and certain of its affiliates for the settlement of claims relating to certain transactions under Section 16 (b) of the Exchange Act. The Company recognized the net proceeds of $3.0 million as a capital contribution from a stockholder and recorded it as an increase to additional paid-in capital, which is reflected within the other line in the consolidated statements of stockholders’ equity for the year ended December 31, 2018.

Commodity Contracts

During the year December 31, 2018, the Company entered into agreements with an affiliate of Brookfield regarding the financial swap of certain commodity contracts. These agreements were entered on a flow-through, cost-reimbursement basis, and did not result in any fees or other amounts payable by the Company to any Brookfield affiliate. During the years ended December 31, 2019 and 2018, a total of $0.5 million and $1.2 million, respectively, was recorded pursuant to these agreements on a cost-reimbursement basis by the Company to the Brookfield counterparty.

Chamblee Class Action Settlement

As discussed in Note 16. Stockholders’ Equity, on August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Common Stock to Orion Holdings in connection with the net losses incurred as a result of the final resolution of the Chamblee Class Action.

Due from affiliates

The $0.5 million and $0.2 million due from affiliates amount reported on the consolidated balance sheets as of December 31, 2019 and 2018, respectively, represents a receivable from certain affiliates of Brookfield, as a result of payments made by the Company on their behalf, primarily related to professional fees and rent for shared corporate headquarters, compensation for certain employees that provided services to both companies and certain information technology services. There was no right of set-off with respect to these receivables from affiliates and the payables to the other Brookfield affiliates described herein, and thus these amounts were separately reported in due from affiliate in the consolidated balance sheets.

Due to affiliates

The $11.5 million due to affiliates amount reported on the consolidated balance sheets as of December 31, 2019, represented (i) $8.6 million payables to affiliates of Brookfield for the Brookfield MSA base management fee for the fourth quarter of 2019, (ii) $1.4 million for services and fees incurred by an affiliate of Brookfield on behalf of the Company related to acquisitions in Spain, (iii) $0.6 million standby fee payable under the Sponsor Line, (iv) $0.5 million payable for commodity contracts executed on behalf of the Company on a cost-reimbursement basis, and (v) $0.4 million payables related to rent, office charges and other services to affiliates of Brookfield related to the Company’ corporate headquarters in New York.

The $7.0 million due to affiliates amount reported in the consolidated balance sheets as of December 31, 2018, primarily represented payables to affiliates of Brookfield of $4.2 million for the Brookfield MSA quarterly base management fee for the fourth quarter of 2018 and $2.8 million for leasehold improvements, rent, office charges and other services associated with the transition to the Company’s new corporate headquarters during 2018.

During the year ended December 31, 2019, the Company paid affiliates of Brookfield $22.4 million for the Brookfield MSA base management fee, $1.9 million representing standby fee interest payable under the Sponsor Line, and $3.6 million for leasehold improvements, rent, office charges and other services with affiliates of Brookfield. During the year ended December 31, 2018, the Company paid $14.0 million for the Brookfield MSA base management, $4.0 million for services and fees paid on behalf of the Company by affiliates of Brookfield related to the acquisition of Saeta; and $3.6 million of additional Sponsor Line standby fee interest. Furthermore, in connection with a bank guarantee issued in support of the Saeta acquisition, Brookfield provided credit support to the Company, and the Company agreed to pay a fee to Brookfield an amount equal to

50% of the savings realized by the Company as a result of Brookfield’s provision of credit support, which amounted to $2.9 million and was paid in the second quarter of 2018.

Agreements with X-Elio Energy

As discussed in Note 3. Acquisitions and Divestitures, on December 18, 2019, the Company acquired an approximately 45 MW portfolio of utility-scale solar photovoltaic power plants in Spain from subsidiaries of X-Elio Energy, S.L. (“X-Elio”). Contemporaneously with the closing of the X-Elio Acquisition, Brookfield and certain of its institutional partners entered into a 50-50 joint venture in respect of X-Elio.

The X-Elio Acquisition was pursuant to three share purchase agreements with X-Elio (collectively the “X-Elio SPAs”), pursuant to which the Company acquired three X-Elio subsidiaries. In connection with the X-Elio Acquisition, on the closing date, the Company entered into a Transitional Services Agreement (the “X-Elio TSA”) with X-Elio. The X-Elio TSA provides for X-Elio to support the Company on a transitional basis by providing certain accounting and other services for an initial three-month term that may be extended at the election of the Company for an additional three-month term. In addition, the subsidiaries acquired by the Company on the closing date were party to existing O&M agreements with X-Elio (collectively, the “X-Elio O&M Agreements”), pursuant to which X-Elio provided O&M services to the acquired solar power facilities. Under the terms of the X-Elio SPAs, the X-Elio O&M Agreements will remain in effect for a maximum 12-month term after the closing date, subject to earlier termination at the Company’s election, for a total consideration of €1.0 million per annum (equivalent to $1.1 million as of December 31, 2019). Under the X-Elio SPAs, certain indemnity and other obligations remain in place post-closing of the acquisition but no post-closing payments are expected to be made by either party in the ordinary course.

SunEdison Matters

SunEdison Bankruptcy and Settlement Agreement with SunEdison

As discussed in Note 1. Nature of Operations and Organization, TerraForm Power entered into the Settlement Agreement with SunEdison on March 6, 2017, which was approved by the Bankruptcy Court. The settlements, mutual intercompany releases, and certain other terms and conditions became effective upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017. The effectiveness of these Settlement Agreement provisions has resolved claims between TerraForm Power and SunEdison, including, among other things, claims of SunEdison against the Company for alleged fraudulent and preferential transfers and claims of the Company against SunEdison, including those outlined in the initial proof of claim filed by the Company in the SunEdison Bankruptcy on September 25, 2016, and on October 7, 2016. Under the Settlement Agreement, all such claims have been mutually released. Moreover, with certain limited exceptions, any agreements between SunEdison Debtors and SunEdison parties to the Settlement Agreement on the one hand and the Company, on the other hand, have been deemed rejected without further liability, claims, or damages on the part of the Company. These exceptions included directors’ and officers’ liability insurance allocation agreements and certain corporate and project-level transition services agreements.

Historical Management Services Agreement with SunEdison

Historically, general and administrative expenses - affiliate primarily represented costs incurred by SunEdison for services provided to the Company pursuant to the management services agreement (the “SunEdison MSA”). Pursuant to the SunEdison MSA, SunEdison agreed to provide or arrange for other service providers to provide management and administrative services to the Company. As consideration for the services provided, the Company agreed to pay SunEdison a base management fee equal to 2.5% of the Company’s cash available for distribution in 2017 but not to exceed $9.0 million. Subsequent to the SunEdison Bankruptcy, SunEdison continued to provide some of these services, including services related to information technology, human resources, tax, treasury, finance and controllership, but stopped providing or reimbursing the Company for other services.

The Company entered into a corporate-level transition services agreement with SunEdison on September 7, 2017 that covered the services that SunEdison continued to provide under the SunEdison MSA and retroactively applied to transition services provided since February 1, 2017. The Company paid SunEdison certain monthly fees in exchange for these services at rates consistent with past practice. Amounts incurred by the Company under this transition services agreement with SunEdison and by SunEdison under the SunEdison MSA totaled $4.5 million for the year ended December 31, 2017, and are reported within general and administrative expenses - affiliate in the consolidated statements of operations. As discussed above, the SunEdison MSA was rejected without further liability, claims or damages on the part of the Company pursuant to the Settlement Agreement upon the closing of the Merger. The corporate-level transition services agreement was extended through

the end of the fourth quarter of 2017 with respect to certain information technology services. Amounts incurred for these services subsequent to the Merger closing date on October 16, 2017 are included within general and administrative expenses in the consolidated statements of operations since SunEdison was no longer an affiliate of the Company.

Historical O&M and Asset Management Services with SunEdison

O&M services, as well as asset management services, were historically provided to the Company substantially by SunEdison pursuant to contractual agreements. The Company has completed its transition away from SunEdison for these services, except for services provided to its 101.6 MW renewable energy facility in Chile. In the first half of 2017, the Company entered into certain transition services agreements with SunEdison to facilitate this transition. These transition services agreements allowed the Company, among other things, to hire employees of SunEdison that were performing these project-level services for the Company and to terminate project-level asset management and O&M services on 10 days advance notice. Total costs incurred for O&M and asset management services from SunEdison were $17.6 million and $26.7 million during the years ended December 31, 2017 and 2017, respectively, and are reported as cost of operations - affiliate in the consolidated statements of operations. Amounts incurred for O&M and asset management services from SunEdison subsequent to the Merger closing date on October 16, 2017 are included within cost of operations in the consolidated statements of operations since SunEdison was no longer an affiliate of the Company.

Historical Engineering, Procurement and Construction Contracts and Module Warranties

SunEdison served as the prime construction contractor for most of the Company’s renewable energy facilities acquired from SunEdison pursuant to engineering, procurement and construction contracts with the Company’s project-level subsidiaries. The Company also generally obtained solar module warranties from SunEdison, including workmanship warranties and output guarantees, for those solar facilities that the Company acquired from SunEdison that utilized SunEdison modules. Third party insurance was procured by SunEdison to back-stop payment of warranty claims for SunEdison modules purchased from January of 2011 through January of 2017.

During the first quarter of 2017, the Company received $7.0 million from SunEdison in satisfaction of outstanding claims made under engineering, procurement and construction contracts, of which $4.8 million related to the Company’s renewable energy facility located in Chile and compensated the relevant project company as the facility’s performance during the warranty period was below that guaranteed by an affiliate of SunEdison under the applicable EPC contract. These receipts were treated as equity contributions from SunEdison within Net SunEdison investment on the consolidated statements of stockholders’ equity for the year ended December 31, 2017. As discussed above, pursuant to the Settlement Agreement entered into with SunEdison, and upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017, these construction and related contracts were rejected without further liability, claims or damages on the part of the Company.

Insurance Allocation Agreements

The Company, TerraForm Global, SunEdison and certain of their respective directors and officers shared $150.0 million of directors’ and officers’ liability insurance policies that covered the period from July 15, 2015 to July 14, 2016 (the “D&O Insurance”). SunEdison and the independent directors of SunEdison entered into an agreement, dated March 27, 2017 and amended on June 7, 2017, with the Company, TerraForm Global, their respective current directors (as of that date) and certain of their respective current officers (as of that date) (the “YieldCo D&O Parties”) related to the D&O Insurance, which included, among other things, an agreement by SunEdison to consent to proposed settlements of up to $32.0 million to be funded from the D&O Insurance for certain lawsuits against the YieldCo D&O Parties. The agreement was approved by the Bankruptcy Court on June 28, 2017.

On August 31, 2017, the Company, TerraForm Global, SunEdison and certain of their respective current and former directors and officers entered into a second agreement related to the D&O insurance, which provided, among other things, that no party to the second D&O insurance allocation agreement would object to the settlement of the Chamblee Class Action (as discussed in Note 20. Commitments and Contingencies) with the use of $13.6 million of the D&O insurance. On September 11, 2017, the Bankruptcy Court granted approval of the second D&O insurance allocation. In connection with the second D&O insurance allocation agreement, the Company and TerraForm Global entered into an agreement pursuant to which TerraForm Global agreed to indemnify and reimburse the Company for certain legal costs and expenses related to the defense or settlement of the Chamblee Class Action that are not covered by the D&O insurance.

In addition to the insurance allocation agreements, from time to time, the Company agreed to orders or stipulations with SunEdison and TerraForm Global in connection with the SunEdison Bankruptcy related to, among other things, insurance proceeds, interim operating protocols, bankruptcy filing protocols and other matters.

Net SunEdison Investment

During the year ended December 31, 2017, SunEdison made net contributions to Terra LLC pursuant to the related party agreements discussed above and in connection with drop down acquisitions. The following table illustrates the detail of Net SunEdison investment for the year ended December 31, 2017, as reported in the consolidated statements of stockholders’ equity:

(in thousands)	Year ended December 31, 2017
General and administrative expenses - affiliate1	$	6,154
TerraForm Power, Inc. equity awards distributed to SunEdison2	(3,372)
Other3	6,986
Net SunEdison investment	$	9,768

———

(1)Represents costs incurred by SunEdison for services provided to the Company pursuant to the SunEdison MSA in excess of cash paid or payable to SunEdison, as well as stock-based compensation expense related to equity awards in the stock of SunEdison and TerraForm Global that was allocated to the Company (as discussed in Note 17. Stock-Based Compensation).

(2)Represents stock-based compensation cost related to equity awards in the Company’s stock which was allocated to SunEdison and TerraForm Global.

(3)Represents cash received from SunEdison in satisfaction of outstanding claims made under engineering, procurement and construction contracts as discussed above.

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Variable Interest Entities

The carrying amounts and classification of the consolidated assets and liabilities of the VIEs included in the Company’s consolidated balance sheets were as follows:

	As of December 31,
(In thousands)	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	44,083	$	69,896
Restricted cash	10,562		10,428
Accounts receivable, net	39,804		31,740
Derivative assets, current	2,461		2,038
Prepaid expenses	3,466		3,194
Other current assets	21,228		16,761
Total current assets	121,604		134,057
Renewable energy facilities, net	3,188,508		3,064,675
Intangible assets, net	690,594		751,377
Restricted Cash	4,454		12,140
Derivative assets	56,852		78,916
Other assets	7,061		2,441
Total assets	$	4,069,073	$	4,043,606
Liabilities
Current liabilities:
Current portion of long-term debt and financing lease obligations	$	55,089	$	64,251
Accounts payable, accrued expenses and other current liabilities	42,685		55,996
Derivative liabilities, current	449		543
Total current liabilities	98,223		120,790
Long-term debt and financing lease obligations, less current portion	932,862		885,760
Operating lease obligations, less current portion	138,816		—
Asset retirement obligations	116,159		86,457
Derivative liabilities	894		3,558
Other liabilities	41,813		39,014
Total liabilities	$	1,328,767	$	1,135,579

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Intangible Assets, Net and Goodwill (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Gross Carrying Amount and Accumulated Amortization of Other Intangible Assets

The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2019:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization		Net Book Value
Licensing agreements	13 years	$	765,451	$	(81,647)	$	683,804
Favorable rate revenue contracts	12 years	745,784		(195,287)		550,497
In-place value of market rate revenue contracts	16 years	688,832		(129,841)		558,991
Total intangible assets, net		$	2,200,067	$	(406,775)	$	1,793,292
Unfavorable rate revenue contracts	8 years	$	48,420	$	(32,556)	$	15,864
Total intangible liabilities, net1		$	48,420	$	(32,556)	$	15,864

———

(1)The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2018:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization		Net Book Value
Licensing contracts1	15 years	$	1,015,824	$	(36,374)	$	979,450
Favorable rate revenue contracts	14 years	738,488		(166,507)		571,981
In-place value of market rate revenue contracts	18 years	532,844		(100,543)		432,301
Favorable rate land leases2	16 years	15,800		(3,128)		12,672
Total intangible assets, net		$	2,302,956	$	(306,552)	$	1,996,404
Unfavorable rate revenue contracts	6 years	$	58,508	$	(41,605)	$	16,903
Unfavorable rate operations and maintenance contracts	1 year	5,000		(3,802)		1,198
Unfavorable rate land lease2	14 years	1,000		(218)		782
Total intangible assets, net3		$	64,508	$	(45,625)	$	18,883

———

(1)Represents the intangible assets recognized under the Saeta acquisition and attributed to licensing contracts in-place from the acquired solar and wind facilities. See Note 3. Acquisitions and Divestitures for additional details.

(2)On January 1, 2019, these amounts were reclassified to right-of-use assets in connection with the adoption of Topic 842. See Note 2. Summary of Significant Accounting Policies and Note 8. Leases for additional details.

(3)The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

Over the next five years, the Company expects to recognize annual amortization on its intangibles as follows:

(In thousands)	2020		2021		2022		2023		2024
Favorable rate revenue contracts	$	47,555	$	44,789	$	43,598	$	43,598	$	43,598
Unfavorable rate revenue contracts	(7,545)		(2,710)		(1,628)		(1,007)		(279)
Total net amortization expense recorded to operating revenues, net	$	40,010	$	42,079	$	41,970	$	42,591	$	43,319
Licensing contracts	$	57,152	$	57,152	$	57,152	$	57,152	$	57,152
In-place value of market rate revenue contracts	38,517		38,517		38,517		38,510		38,503
Total amortization expense recorded to depreciation, accretion and amortization expense	$	95,669	$	95,669	$	95,669	$	95,662	$	95,655

Schedule of Goodwill

The following table presents the activity of the goodwill balance for the years ended December 31, 2019, and 2018:

(In thousands)	Goodwill
Balance as of December 31, 2017	$	—
Goodwill resulting from business combination1	115,381
Adjustments during the period1	7,726
Foreign exchange differences	(2,554)
Balance as of December 31, 2018	120,553
Adjustments during the period2	10,196
Foreign exchange differences	(2,797)
Balance as of December 31, 2019	$	127,952

———

(1)Represents the excess purchase price over the estimated fair value of net assets acquired from Saeta and is primarily attributable to deferred tax liabilities and adjustment to the fair value of certain non-recourse project long-term debt. See Note 3. Acquisitions and Divestitures for additional details.

(2)Represents adjustments to the purchase price allocation of the assets acquired and liabilities assumed from the Saeta acquisition. See Note 3. Acquisitions and Divestitures for additional details.

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Concentration of Credit Risks - Major Customers Operating Revenues (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Operating revenues, net	$ 206,734	$ 253,808	$ 255,366	$ 225,332	$ 213,093	$ 246,042	$ 179,888	$ 127,547	$ 941,240	$ 766,570	$ 610,471
Accounts receivable, net	167,865				145,161				167,865	145,161
Accounts Receivable
Concentration Risk [Line Items]
Accounts receivable, net	91,196				74,454				91,196	74,454
Spain
Concentration Risk [Line Items]
Operating revenues, net									338,669	186,655	0
Wind
Concentration Risk [Line Items]
Operating revenues, net									286,139	280,949
Solar
Concentration Risk [Line Items]
Operating revenues, net									316,433	298,966
Comisión Nacional de los Mercados y la Competencia (CNMC) | Accounts Receivable
Concentration Risk [Line Items]
Accounts receivable, net	78,474				64,739				78,474	64,739
Comisión Nacional de los Mercados y la Competencia (CNMC) | Regulated Solar and Wind
Concentration Risk [Line Items]
Operating revenues, net									$ 240,714	$ 127,912
Concentration risk (percent)									25.60%	16.70%
Tennessee Valley Authority | Accounts Receivable
Concentration Risk [Line Items]
Accounts receivable, net	$ 12,722				$ 9,715				$ 12,722	$ 9,715
Tennessee Valley Authority | Regulated Solar and Wind
Concentration Risk [Line Items]
Operating revenues, net									$ 93,920	$ 90,283
Concentration risk (percent)									10.00%	11.80%
Tennessee Valley Authority | Wind
Concentration Risk [Line Items]
Operating revenues, net											$ 79,773
Concentration risk (percent)											13.10%
San Diego Gas & Electric | Solar
Concentration Risk [Line Items]
Operating revenues, net											$ 63,905
Concentration risk (percent)											10.50%

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Segment Reporting - Income Statement Summary (Details)	3 Months Ended								12 Months Ended
	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) business	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | business									3
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net	$ 206,734,000	$ 253,808,000	$ 255,366,000	$ 225,332,000	$ 213,093,000	$ 246,042,000	$ 179,888,000	$ 127,547,000	$ 941,240,000	$ 766,570,000	$ 610,471,000
Depreciation, accretion and amortization expense									434,110,000	341,837,000	246,720,000
Impairment of renewable energy facilities									0	15,240,000	1,429,000
Other operating costs and expenses									393,700,000	339,514,000	321,599,000
Operating income (loss)	(10,967,000)	40,365,000	54,928,000	29,104,000	8,063,000	56,666,000	27,299,000	(22,049,000)	113,430,000	69,979,000	40,723,000
Interest expense, net	51,421,000	89,393,000	71,041,000	86,287,000	72,349,000	72,416,000	50,892,000	53,554,000	298,142,000	249,211,000	262,003,000
Other non-operating (income) expenses, net									9,975,000	(13,615,000)	34,664,000
Income tax expense (benefit)									11,898,000	(12,290,000)	(19,641,000)
Net income (loss)	(91,388,000)	$ (62,313,000)	$ (16,827,000)	$ (36,057,000)	(30,351,000)	$ (19,051,000)	$ (27,612,000)	$ (76,313,000)	(206,585,000)	(153,327,000)	(236,303,000)
Cash Flows
Capital expenditures									21,184,000	22,445,000	8,392,000
Balance Sheet
Total assets	10,058,636,000				9,330,354,000				10,058,636,000	9,330,354,000	6,387,021,000
Solar
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									316,433,000	298,966,000
Impairment of renewable energy facilities										15,200,000
Wind
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									286,139,000	280,949,000
Regulated Solar and Wind
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									338,668,000	186,655,000
Segments | Solar
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									316,433,000	298,966,000	337,233,000
Depreciation, accretion and amortization expense									118,564,000	109,809,000	108,695,000
Impairment of renewable energy facilities										15,240,000	1,429,000
Other operating costs and expenses									66,334,000	74,778,000	65,213,000
Operating income (loss)									131,535,000	99,139,000	161,896,000
Interest expense, net									68,441,000	63,571,000	70,439,000
Other non-operating (income) expenses, net									(7,893,000)	(4,248,000)	(36,399,000)
Income tax expense (benefit)									2,309,000	(20,346,000)	0
Net income (loss)									68,678,000	60,162,000	127,856,000
Cash Flows
Capital expenditures									2,223,000	4,325,000	302,000
Balance Sheet
Total assets	3,509,076,000				2,762,977,000				3,509,076,000	2,762,977,000	2,897,036,000
Segments | Wind
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									286,139,000	280,949,000	273,238,000
Depreciation, accretion and amortization expense									175,842,000	151,472,000	135,785,000
Impairment of renewable energy facilities										0	0
Other operating costs and expenses									142,031,000	123,203,000	105,817,000
Operating income (loss)									(31,734,000)	6,274,000	31,636,000
Interest expense, net									58,105,000	50,712,000	77,398,000
Other non-operating (income) expenses, net									(455,000)	(108,000)	3,650,000
Income tax expense (benefit)									193,000	79,000	0
Net income (loss)									(89,577,000)	(44,409,000)	(49,412,000)
Cash Flows
Capital expenditures									15,426,000	12,219,000	7,670,000
Balance Sheet
Total assets	3,716,447,000				3,733,049,000				3,716,447,000	3,733,049,000	3,400,858,000
Segments | Regulated Solar and Wind
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									338,668,000	186,655,000
Depreciation, accretion and amortization expense									138,213,000	79,026,000
Impairment of renewable energy facilities										0
Other operating costs and expenses									90,516,000	46,289,000
Operating income (loss)									109,939,000	61,340,000
Interest expense, net									54,727,000	15,510,000
Other non-operating (income) expenses, net									3,994,000	(2,261,000)
Income tax expense (benefit)									1,326,000	10,558,000
Net income (loss)									49,892,000	37,533,000
Cash Flows
Capital expenditures									599,000	0
Balance Sheet
Total assets	2,731,892,000				2,748,126,000				2,731,892,000	2,748,126,000
Corporate
Segment Reporting Information, Profit (Loss) [Abstract]
Operating revenues, net									0	0	0
Depreciation, accretion and amortization expense									1,491,000	1,530,000	2,240,000
Impairment of renewable energy facilities										0	0
Other operating costs and expenses									94,819,000	95,244,000	150,569,000
Operating income (loss)									(96,310,000)	(96,774,000)	(152,809,000)
Interest expense, net									116,869,000	119,418,000	114,166,000
Other non-operating (income) expenses, net									14,329,000	(6,998,000)	67,413,000
Income tax expense (benefit)									8,070,000	(2,581,000)	(19,641,000)
Net income (loss)									(235,578,000)	(206,613,000)	(314,747,000)
Cash Flows
Capital expenditures									2,936,000	5,901,000	420,000
Balance Sheet
Total assets	$ 101,221,000				$ 86,202,000				$ 101,221,000	$ 86,202,000	$ 89,127,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Income before Income Tax, Domestic and Foreign

The income tax expense (benefit) was calculated based on the income and losses before income tax between U.S. and foreign operations as follows:

(In thousands)	2019		2018		2017
(Loss) income before income taxes:
United States	$	(212,995)	$	(182,289)	$	(292,190)
Foreign	18,308		16,672		36,246
Loss before income taxes	$	(194,687)	$	(165,617)	$	(255,944)

Schedule of Components of Income Tax Expense (Benefit)

The income tax provision consisted of the following:

(In thousands)	Current		Deferred		Total
Year ended December 31, 2019
U.S. federal	$	145	$	4,728	$	4,873
State and local	134		3,197		3,331
Foreign	4,636		(942)		3,694
Total expense	4,915		6,983		11,898
Tax benefit in equity	—		(978)		(978)
Total	$	4,915	$	6,005	$	10,920
Year ended December 31, 2018
U.S. federal	$	(461)	$	(18,301)	$	(18,762)
State and local	323		(4,376)		(4,053)
Foreign	2,739		7,786		10,525
Total expense (benefit)	2,601		(14,891)		(12,290)
Tax expense in equity	—		2,826		2,826
Total	$	2,601	$	(12,065)	$	(9,464)
Year ended December 31, 2017
U.S. federal	$	(45)	$	(20,489)	(20,534)
State and local	95		(1,211)		(1,116)
Foreign	220		1,789		2,009
Total expense (benefit)	270		(19,911)		(19,641)
Tax expense in equity	—		14,081		14,081
Total	$	270	$	(5,830)	$	(5,560)

Schedule of Effective Income Tax Rate Reconciliation

The income tax provision differed from the expected amounts computed by applying the statutory U.S. federal income tax rate of 21% as of December 31, 2019 and December 31, 2018 and 35% as of December 31, 2017, to loss before income taxes, as follows:

	Year Ended December 31,
	2019		2018		2017
Income tax benefit at U.S. federal statutory rate	21.0	%	21.0	%	35.0	%
Increase (reduction) in income taxes:
State income taxes, net of U.S. federal benefit	5.9		5.0		4.0
Foreign operations	(2.0)		(0.5)		8.7
Non-controlling interests	(8.0)		(25.9)		(9.4)
Permanent differences	(0.2)		(1.6)		—
Tax Act rate change impact	—		—		2.0
Return to provision	—		—		2.8
Change in valuation allowance	(22.4)		7.8		(34.1)
Other	(0.4)		1.6		—
Effective tax rate	(6.1)	%	7.4	%	9.0	%

Schedule of Deferred Tax Assets and Liabilities

The tax effects of the major items recorded as deferred tax assets and liabilities were as follows:

	As of December 31,
(In thousands)	2019		2018
Deferred tax assets:
Net operating losses and tax credit carryforwards	$	623,858	$	587,833
Derivative Liabilities	26,087		33,261
Interest expense limitation carryforward	117,598		67,887
Total deferred tax assets	767,543		688,981
Valuation allowance	(413,884)		(386,336)
Net deferred tax assets	353,659		302,645
Deferred tax liabilities:
Investment in partnership	270,237		221,694
Renewable energy facilities	107,908		30,261
Intangible assets	169,195		229,363
Other	858		176
Total deferred tax liabilities	548,198		481,494
Net deferred tax liabilities	$	194,539	$	178,849

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Stock-Based Compensation - Narrative (Details) - USD ($)		3 Months Ended	12 Months Ended
	Mar. 18, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accelerated compensation cost		$ 7,000,000.0
Outstanding stock options (in shares)		0	0	0
Unrecognized compensation cost		$ 0	$ 0	$ 0
Affiliated Entity | TerraForm Global, LLC
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accelerated compensation cost		$ 1,000,000.0
Employee Stock Option and Restricted Stock | General and Administrative Expense | SunEdison, Inc. and TerraFrom Global, Inc.
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense					$ 5,500,000
Employee Stock Option and Restricted Stock | TerraForm Power | General and Administrative Expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense					11,300,000
Employee Stock Option and Restricted Stock | SunEdison, Inc. and TerraFrom Global, Inc.
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense					3,400,000
Employee Stock Option and Restricted Stock | SunEdison
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense					$ 2,200,000
Restricted Stock Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested RSAs (in shares)		0	0	0	0	366,195
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested RSAs (in shares)		103,300	191,936	103,300	0	1,622,953
Options vested in period, fair value			$ 300,000	$ 0	$ 16,700,000
Weighted average grant date fair value per share for shares granted (usd per share)			$ 12.17	$ 11.15	$ 12.22
Compensation not yet recognized		$ 900,000	$ 1,600,000	$ 900,000
Restricted stock granted (in shares)			156,550	117,424	523,877
Vesting period			3 years	3 years
Time Based RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock granted (in shares)					523,877
Aggregate fair value					$ 6,400,000
Common Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for issuance (in shares)			3,734,185
Minimum | Time Based RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					6 months
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term	10 years
Maximum | Time Based RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					4 years

XML

Acquisitions and Divestitures - Out of Period Adjustments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Sep. 30, 2019	Jun. 12, 2019	Dec. 31, 2018	Jun. 12, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Intangible assets, net	$ (1,793,292)			$ (1,996,404)
Long-term debt	(6,228,936)
Renewable energy facilities, net				6,470,026
Goodwill	(127,952)			(120,553)		$ 0
Deferred income taxes	194,539			$ 178,849
Restatement Adjustment | Correction to Intangible Assets, Long-term Debt And Goodwill for Business Acquisition Reported in Quarters June 30, 2019 and September 30 2019
Business Acquisition [Line Items]
Intangible assets, net	258,300
Long-term debt	28,500
Renewable energy facilities, net	258,300
Goodwill	22,000
Deferred income taxes	$ 6,500
Saeta Yield
Business Acquisition [Line Items]
Goodwill			$ (133,301)		$ (123,106)
Saeta Yield | Wind
Business Acquisition [Line Items]
Goodwill			$ (29,500)
Saeta Yield | Wind | Previously Reported
Business Acquisition [Line Items]
Intangible assets, net		$ (258,300)

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Income Taxes - Income Tax Expense Calculated Using Pretax Book Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Loss before income taxes	$ (194,687)	$ (165,617)	$ (255,944)
United States
Operating Loss Carryforwards [Line Items]
Loss before income taxes	(212,995)	(182,289)	(292,190)
Foreign
Operating Loss Carryforwards [Line Items]
Loss before income taxes	$ 18,308	$ 16,672	$ 36,246

XML

Fair Value of Financial Instruments - Fair Value of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Carrying Amount	$ 6,235,382	$ 5,761,845
Fair Value	$ 6,512,188	$ 5,789,702

XML

Long-Term Debt - Non-Recourse Long-term Debt (Details) € in Millions									3 Months Ended	12 Months Ended
	Dec. 31, 2019 USD ($) MW	Dec. 27, 2019 USD ($) MW	Dec. 10, 2019 USD ($) business MW	Nov. 24, 2019 USD ($) MW	Sep. 25, 2019 USD ($) MW	Aug. 30, 2019 USD ($) MW	May 29, 2019 USD ($) MW	Apr. 30, 2019 USD ($) business MW	Dec. 31, 2019 USD ($) MW	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 27, 2019 EUR (€) MW	Dec. 18, 2019 USD ($) MW	Dec. 10, 2019 EUR (€) business MW
Debt Instrument [Line Items]
Long-term debt	$ 6,228,936,000								$ 6,228,936,000	$ 6,228,936,000
Loss on modification and extinguishment of debt, net									31,100,000	26,953,000	$ 1,480,000	$ 81,099,000
Default amount	$ 159,300,000								$ 159,300,000	$ 159,300,000	$ 166,400,000
X-Elio PV Acquisition
Debt Instrument [Line Items]
Capacity of power (MW) | MW	15.1								15.1	15.1				45
Interest rate swaps
Debt Instrument [Line Items]
Fixed derivative rate							2.30%
Non-recourse Project Financing | Spain
Debt Instrument [Line Items]
Capacity of power (MW) | MW		50.0	236.0										50.0		236.0
Basis spread on variable rate			1.65%
Increase in basis spread on variable rate			0.20%
Fixed derivative rate		3.70%	1.55%										3.70%		1.55%
Long-term debt		$ 239,500,000	$ 264,400,000										€ 213.6		€ 235.8
Number of subsidiaries | business			5												5
Upsize in debt		$ 47,100,000											€ 42.0
Percentage of debt hedged		80.00%	80.00%										80.00%		80.00%
Non-recourse Project Financing | URUGUAY
Debt Instrument [Line Items]
Capacity of power (MW) | MW								95
Fixed derivative rate								2.78%
Interest rate								2.60%
Long-term debt								$ 204,000,000.0
Number of subsidiaries | business								2
Upsize in debt								$ 57,500,000
Fixed interest rate, of balance								46.00%
Non-recourse Project Financing | Tranche A | Spain
Debt Instrument [Line Items]
Long-term debt		$ 164,200,000											€ 146.4
Non-recourse Project Financing | Tranche A | URUGUAY
Debt Instrument [Line Items]
Long-term debt								$ 103,000,000.0
Percentage of debt hedged								90.00%
Non-recourse Project Financing | Tranche A | Euribor | Spain
Debt Instrument [Line Items]
Basis spread on variable rate		1.90%
Increase in basis spread on variable rate		0.20%
Variable rate increase, term		5 years
Non-recourse Project Financing | Tranche B | Spain
Debt Instrument [Line Items]
Interest rate		2.55%											2.55%
Long-term debt		$ 75,300,000											€ 67.2
Non-recourse Project Financing | Tranche B | URUGUAY
Debt Instrument [Line Items]
Long-term debt								$ 72,000,000.0
Secured Debt
Debt Instrument [Line Items]
Fixed interest rate, of balance	3800.00%								3800.00%	3800.00%
Secured Debt | X-Elio PV Acquisition
Debt Instrument [Line Items]
Debt assumed in acquisition														$ 151,700,000
Assumed debt, average interest rate	2.80%
Secured Debt | Non-recourse Project Financing
Debt Instrument [Line Items]
Face amount of debt instrument							$ 104,100,000
Capacity of power (MW) | MW							137.7
Variable rate increase, term							4 years
Term of instrument							15 years
Secured Debt | Non-recourse Project Financing | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate							2.00%
Increase in basis spread on variable rate							0.125%
Secured Debt | 3.2% Senior Notes Due 2032
Debt Instrument [Line Items]
Face amount of debt instrument						$ 131,000,000.0
Capacity of power (MW) | MW						111
Term of instrument						13 years
Interest rate						3.20%
Secured Debt | 3.55% Senior Notes
Debt Instrument [Line Items]
Face amount of debt instrument				$ 171,500,000
Capacity of power (MW) | MW				200.6
Term of instrument				20 years
Interest rate				3.55%
Long-term debt				$ 69,100,000
Loss on modification and extinguishment of debt, net										$ 300,000
Bridge Facility
Debt Instrument [Line Items]
Face amount of debt instrument	$ 474,600,000				$ 475,000,000.0				$ 474,600,000	$ 474,600,000
Capacity of power (MW) | MW					320
Debt instrument extension term										1 year
Bridge Facility | Non-recourse Project Financing
Debt Instrument [Line Items]
Debt instrument extension term					1 year
Bridge Facility | Non-recourse Project Financing | First Six Months | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate					1.00%
Bridge Facility | Non-recourse Project Financing | Next Six Months | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate					1.50%
Bridge Facility | Non-recourse Project Financing | Six Months, Thereafter | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate					1.75%
Term Loan | Non-recourse Project Financing | URUGUAY
Debt Instrument [Line Items]
Long-term debt								$ 29,000,000.0
Term Loan | Non-recourse Project Financing | LIBOR | Minimum | URUGUAY
Debt Instrument [Line Items]
Basis spread on variable rate								1.94%
Term Loan | Non-recourse Project Financing | LIBOR | Maximum | URUGUAY
Debt Instrument [Line Items]
Basis spread on variable rate								2.94%

XML

Variable Interest Entities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 237,480	$ 248,524	$ 128,087
Accounts receivable, net	167,865	145,161
Derivative assets, current	15,819	14,371
Prepaid expenses	13,514	13,116
Other current assets	57,682	52,033
Total current assets	553,347	501,185
Renewable energy facilities, net		6,470,026
Intangible assets, net	1,793,292	1,996,404
Restricted Cash	76,363	116,501	42,694
Derivative assets	57,717	90,984
Other assets	44,504	34,701
Total assets	10,058,636	9,330,354	$ 6,387,021
Current liabilities:
Current portion of long-term debt and financing lease obligations	441,951	464,332
Accounts payable, accrued expenses and other current liabilities	178,796	181,400
Total current liabilities	666,226	688,282
Long-term debt and financing lease obligations, less current portion	5,793,431	5,297,513
Operating lease obligations, less current portion	272,894
Asset retirement obligations	287,288	212,657
Derivative liabilities	101,394	93,848
Other liabilities	112,072	90,788
Total liabilities	7,427,844	6,561,937
Consolidated variable interest entities
Current assets:
Cash and cash equivalents	44,083	69,896
Restricted cash	10,562	10,428
Accounts receivable, net	39,804	31,740
Derivative assets, current	2,461	2,038
Prepaid expenses	3,466	3,194
Other current assets	21,228	16,761
Total current assets	121,604	134,057
Renewable energy facilities, net	3,188,508	3,064,675
Intangible assets, net	690,594	751,377
Restricted Cash	4,454	12,140
Derivative assets	56,852	78,916
Other assets	7,061	2,441
Total assets	4,069,073	4,043,606
Current liabilities:
Current portion of long-term debt and financing lease obligations	55,089	64,251
Accounts payable, accrued expenses and other current liabilities	42,685	55,996
Derivative liabilities, current	449	543
Total current liabilities	98,223	120,790
Long-term debt and financing lease obligations, less current portion	932,862	885,760
Operating lease obligations, less current portion	138,816
Asset retirement obligations	116,159	86,457
Derivative liabilities	894	3,558
Other liabilities	41,813	39,014
Total liabilities	$ 1,328,767	$ 1,135,579

XML

Acquisitions and Divestitures - Intangibles (Details) - USD ($) $ in Thousands	Sep. 26, 2019	Jun. 12, 2018
WGL Acquisition | Favorable rate revenue contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Fair Value	$ 27,400
Weighted Average Amortization Period (In years)	16 years
WGL Acquisition | In-place value of market rate revenue contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Fair Value	$ 141,425
Weighted Average Amortization Period (In years)	15 years
WGL Acquisition | Unfavorable rate revenue contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Fair Value	$ 7,650
Weighted Average Amortization Period (In years)	2 years
Saeta Yield | Licensing agreements
Acquired Finite-Lived Intangible Assets [Line Items]
Fair Value		$ 744,005
Weighted Average Amortization Period (In years)		14 years

XML

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Summarized Financial Information by Reportable Segment

The following table reflects summarized financial information for the Company’s reportable segments for the years ended December 31, 2019, 2018 and 2017:

	Year Ended December 31, 2019
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	316,433	$	286,139	$	338,668	$	—	$	941,240
Depreciation, accretion and amortization expense	118,564		175,842		138,213		1,491		434,110
Other operating costs and expenses	66,334		142,031		90,516		94,819		393,700
Operating income (loss)	131,535		(31,734)		109,939		(96,310)		113,430
Interest expense, net	68,441		58,105		54,727		116,869		298,142
Other non-operating (income) expenses, net	(7,893)		(455)		3,994		14,329		9,975
Income tax expense (benefit)	2,309		193		1,326		8,070		11,898
Net income (loss)	$	68,678	$	(89,577)	$	49,892	$	(235,578)	$	(206,585)
Cash Flows
Capital expenditures	$	2,223	$	15,426	$	599	$	2,936	$	21,184
Balance Sheet
Total assets1	3,509,076		3,716,447		2,731,892		101,221		10,058,636

	Year Ended December 31, 2018
(In thousands)	Solar		Wind		Regulated Solar and Wind		Corporate		Total
Operating revenues, net	$	298,966	$	280,949	$	186,655	$	—	$	766,570
Depreciation, accretion and amortization expense	109,809		151,472		79,026		1,530		341,837
Impairment of renewable energy facilities	15,240		—		—		—		15,240
Other operating costs and expenses	74,778		123,203		46,289		95,244		339,514
Operating income (loss)	99,139		6,274		61,340		(96,774)		69,979
Interest expense, net	63,571		50,712		15,510		119,418		249,211
Other non-operating income, net	(4,248)		(108)		(2,261)		(6,998)		(13,615)
Income tax (benefit) expense	(20,346)		79		10,558		(2,581)		(12,290)
Net income (loss)	$	60,162	$	(44,409)	$	37,533	$	(206,613)	$	(153,327)
Cash Flows
Capital expenditures	$	4,325	$	12,219	$	—	$	5,901	$	22,445
Balance Sheet
Total assets1	2,762,977		3,733,049		2,748,126		86,202		9,330,354

	Year Ended December 31, 2017
(In thousands)	Solar		Wind		Corporate		Total
Operating revenues, net	$	337,233	$	273,238	$	—	$	610,471
Depreciation, accretion and amortization expense	108,695		135,785		2,240		246,720
Impairment of renewable energy facilities	1,429		—		—		1,429
Other operating costs and expenses	65,213		105,817		150,569		321,599
Operating income (loss)	161,896		31,636		(152,809)		40,723
Interest expense, net	70,439		77,398		114,166		262,003
Other non-operating (income) expenses, net	(36,399)		3,650		67,413		34,664
Income tax benefit	—		—		(19,641)		(19,641)
Net income (loss)	$	127,856	$	(49,412)	$	(314,747)	$	(236,303)
Cash Flows
Capital expenditures	$	302	$	7,670	$	420	$	8,392
Balance Sheet
Total assets1	2,897,036		3,400,858		89,127		6,387,021

———

(1)As of December 31, 2019, 2018 and 2017, respectively.

Reconciliation of Revenue from Segments to Consolidated

The following table reflects operating revenues, net earned during the years ended December 31, 2019, 2018 and 2017, by geographic location:

	Year Ended December 31,
(In thousands)	2019		2018		2017
United States	$	457,718	$	473,950	$	519,551
Canada	43,672		41,174		44,636
Spain	338,669		186,655		—
Portugal	38,833		17,269		—
United Kingdom	1,639		1,597		15,002
Uruguay	29,573		17,302		—
Chile	31,136		28,623		31,282
Total operating revenues, net	$	941,240	$	766,570	$	610,471

Reconciliation of Assets from Segment to Consolidated

The following table is a summary of long-lived assets, net by geographic area:

	As of December 31,
(In thousands)	2019		2018
United States (including Puerto Rico)	$	5,722,092	$	5,030,483
Canada	366,862		362,829
Spain	2,574,546		2,503,420
Portugal	229,629		251,053
United Kingdom	17,289		13,183
Uruguay	261,189		264,798
Chile	155,098		161,217
Total long-lived assets, net	9,326,705		8,586,983
Current assets	553,347		501,185
Other non-current assets	178,584		242,186
Total assets	$	10,058,636	$	9,330,354

XML

Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (loss) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018
AOCI [Roll Forward]
Beginning balance		$ 2,734,922,000	$ 2,387,712,000	$ 2,729,494,000
Cumulative-effect adjustment	[1]				$ 20,106,000
Other Comprehensive Income (Loss), Net of Tax		(29,217,000)	(13,761,000)	40,406,000
Accumulated other comprehensive (loss) income		11,645,000	40,238,000
Ending balance		2,607,908,000	2,734,922,000	2,387,712,000
United Kingdom | Gain on sale of renewable energy facilities
AOCI [Roll Forward]
Reclassification of net realized loss (gain) into earnings:			23,600,000
ASU 2018-02
AOCI [Roll Forward]
Cumulative-effect adjustment, tax					9,357,000
AOCI Attributable to Parent
AOCI [Roll Forward]
Beginning balance		40,238,000	48,018,000	22,912,000
Cumulative-effect adjustment	[1]				5,193,000
Other Comprehensive Income (Loss), Net of Tax		(28,593,000)	(12,984,000)	25,749,000
Ending balance		11,645,000	40,238,000	48,018,000
AOCI Attributable to Parent | ASU 2017-12
AOCI [Roll Forward]
Cumulative-effect adjustment					(4,164,000)
Cumulative-effect adjustment, tax					1,600,000
AOCI Attributable to Parent | ASU 2018-02
AOCI [Roll Forward]
Cumulative-effect adjustment					9,368,000
Foreign Currency Translation Adjustments
AOCI [Roll Forward]
Beginning balance		(8,405,000)	(13,412,000)	(22,133,000)
Net unrealized (loss) gain arising during the period, net of tax		15,652,000	(9,517,000)
Reclassification of net realized loss (gain) into earnings:		0
Other Comprehensive Income (Loss), Net of Tax		15,652,000	(9,517,000)
Accumulated other comprehensive (loss) income		7,247,000	(8,405,000)	2,908,000
Ending balance		7,247,000	(8,405,000)	(13,412,000)
Foreign Currency Translation Adjustments | ASU 2017-12
AOCI [Roll Forward]
Cumulative-effect adjustment					0
Foreign Currency Translation Adjustments | ASU 2018-02
AOCI [Roll Forward]
Cumulative-effect adjustment					14,524,000
Hedging Activities
AOCI [Roll Forward]
Beginning balance		48,643,000	61,430,000	45,045,000
Other Comprehensive Income (Loss), Net of Tax				15,365,000
Accumulated other comprehensive (loss) income		3,774,000		60,410,000
Ending balance		4,398,000	48,643,000	61,430,000
Hedging Activities | ASU 2017-12
AOCI [Roll Forward]
Cumulative-effect adjustment					(4,164,000)
Cumulative-effect adjustment, tax					1,579,000
Hedging Activities | ASU 2018-02
AOCI [Roll Forward]
Cumulative-effect adjustment					$ (5,156,000)
Foreign Currency Translation Adjustments Including Portion Attributable to Noncontrolling Interest
AOCI [Roll Forward]
Net unrealized (loss) gain arising during the period, net of tax				10,300,000
Reclassification of net realized loss (gain) into earnings:			0	14,741,000
Other Comprehensive Income (Loss), Net of Tax				25,041,000
Reclassification from realized loss (gain) into earnings, tax		0	0	8,858,000
Net unrealized (loss) gain arising during the period, tax		0	3,891,000	3,238,000
AOCI Including Portion Attributable to Noncontrolling Interest
AOCI [Roll Forward]
Net unrealized (loss) gain arising during the period, net of tax		(26,638,000)	(8,351,000)	27,912,000
Reclassification of net realized loss (gain) into earnings:		(2,579,000)	(5,410,000)	12,494,000
Other Comprehensive Income (Loss), Net of Tax		(29,217,000)	(13,761,000)	40,406,000
Accumulated other comprehensive (loss) income		11,021,000	39,461,000	63,318,000
Hedging Activities Including Noncontrolling Interest
AOCI [Roll Forward]
Net unrealized (loss) gain arising during the period, net of tax		(42,290,000)	1,166,000	17,612,000
Reclassification of net realized loss (gain) into earnings:		(2,579,000)	(5,410,000)	(2,247,000)
Other Comprehensive Income (Loss), Net of Tax		(44,869,000)	(4,244,000)
Accumulated other comprehensive (loss) income			47,866,000
Reclassification from realized loss (gain) into earnings, tax		0	4,938,000	443,000
Net unrealized (loss) gain arising during the period, tax		978,000	3,729,000	2,428,000
AOCI Attributable to Noncontrolling Interest
AOCI [Roll Forward]
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest		(624,000)	(777,000)	14,657,000
Plus: Reallocation from non-controlling interests as a result of SunEdison exchange				(643,000)
Foreign Currency Translation Adjustments Attributable to Noncontrolling Interest
AOCI [Roll Forward]
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest		0	0	8,665,000
Plus: Reallocation from non-controlling interests as a result of SunEdison exchange				(7,655,000)
Hedge Activities Attributable to Noncontrolling Interest
AOCI [Roll Forward]
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest		$ (624,000)	$ (777,000)	5,992,000
Plus: Reallocation from non-controlling interests as a result of SunEdison exchange				$ 7,012,000

[1] Represents the effect of the adoption of Accounting Standards Update (“ASU”) No. 2014-09, ASU No. 2016-08, ASU No. 2017-12 and ASU No. 2018-02 as of January 1, 2018.

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Related Parties - Sponsor Line Agreement and New York Office Lease (Details) - USD ($)		12 Months Ended
	Oct. 16, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 08, 2019	May 31, 2018	Feb. 06, 2018	Oct. 17, 2017
Related Party Transaction [Line Items]
Interest expense incurred		$ 4,200,000
Sponsor Line Agreement | Revolving Credit Facility
Related Party Transaction [Line Items]
Revolver repayments			$ 86,000,000.0
Interest expense incurred			5,200,000	$ 900,000
Line of Credit | Revolving Credit Facility
Related Party Transaction [Line Items]
Aggregate principal amount					$ 800,000,000.00
Line of Credit | Sponsor Line Agreement | Revolving Credit Facility
Related Party Transaction [Line Items]
Aggregate principal amount	$ 500,000,000.0
Percentage of capital stock	10000.00%
Line of Credit | New Revolver | Revolving Credit Facility
Related Party Transaction [Line Items]
Aggregate principal amount							$ 600,000,000.0	$ 450,000,000.0
Line of Credit | Grand Duchy of Luxembourg | Sponsor Line Agreement | Revolving Credit Facility
Related Party Transaction [Line Items]
Term of instrument	3 years
LIBOR | Line of Credit | Sponsor Line Agreement | Revolving Credit Facility
Related Party Transaction [Line Items]
Basis spread on variable rate	3.00%
LIBOR | Line of Credit | New Revolver | Revolving Credit Facility
Related Party Transaction [Line Items]
Standby fee	50.00%
Affiliated Entity | Upfront Payment On Line Of Credit
Related Party Transaction [Line Items]
Amount of related party transaction	$ 5,000,000.0
Percentage of line of credit paid to affiliate	1.00%
Affiliated Entity | Relocation Of Corporate Headquarters | Brookfield and Affiliates
Related Party Transaction [Line Items]
Term of contract						10 years
Related party charges		$ 900,000	$ 800,000

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Non-Controlling Interests (Tables)

12 Months Ended

Dec. 31, 2019

Noncontrolling Interest [Abstract]

Redeemable Noncontrolling Interest

The following table presents the activity of the redeemable non-controlling interests balance for the years ended December 31, 2019, 2018 and 2017:

(In thousands)	Redeemable Non-controlling Interests
Balance as of December 31, 2016	$	165,975
Distributions	(7,818)
Accretion	6,729
Net income	1,596
Reclassification of Invenergy Wind Interest to non-controlling interests1	(131,822)
Balance as of December 31, 2017	34,660
Cumulative-effect adjustment2	(4,485)
Distributions	(2,458)
Consolidation of redeemable non-controlling interests in acquired renewable energy facilities	55,117
Repurchases of redeemable non-controlling interests, net	(58,014)
Net income	9,209
Exchange differences	(534)
Balance as of December 31, 2018	33,495
Distributions	(1,220)
Repurchases of redeemable non-controlling interests, net3	(4,753)
Non-cash redemption of redeemable non-controlling interests	7,345
Net loss	(11,983)
Balance as of December 31, 2019	$	22,884

———

(1) During the year ended December 31, 2017, the Company recorded $6.7 million adjustment to the value of the Invenergy Wind redeemable non-controlling interest, representing the excess of the future redemption value over its carrying amount based on the SEC guidance in ASC 480-10-S99-3A. Historically, the Company was accreting the redemption value of the Invenergy Wind redeemable non-controlling interest over the redemption period using the straight-line method and accretion adjustments were recorded against additional paid-in capital. As part of the Settlement Agreement, the Option Agreement between Terra LLC and Sun Edison LLC with respect to Invenergy Wind’s remaining 9.9% interest in certain subsidiaries of the Company was rejected upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017. As a result, the Company is no longer obligated to perform on its Option Agreement, and as of October 16, 2017, the Invenergy Wind non-controlling interest amount of $131.8 million was no longer considered redeemable and was reclassified to non-controlling interests as of such date. The redemption adjustments recorded in additional paid-in capital will remain in additional paid-in capital.

(2)See discussion in Note 2. Summary of Significant Accounting Policies regarding the Company’s adoption of ASU No. 2014-09 and ASU No. 2016-08 as of January 1, 2018.

(3)During the year-ended December 31, 2019, the Company purchased the tax equity investors’ interests in certain distributed generation projects in the United States for a combined consideration of $3.9 million, which resulted in increasing the Company’s ownership interest in the related projects to 100%. The difference between the consideration paid and the carrying amounts of the non-controlling interests was recorded as an adjustment to additional paid-in capital within Purchase of (redeemable) non-controlling interests in the consolidated statement of stockholders’ equity.

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Summary of Significant Accounting Policies - Other Narrative (Details)		12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) MW	Jan. 01, 2018 USD ($)
Property, Plant and Equipment [Line Items]
Allowance for doubtful accounts		$ 1,400,000	$ 1,600,000
Provision for bad debt		200,000	100,000	$ (1,500,000)
Write-offs of accounts receivable		0	0	0
Impairment of renewable energy facilities		0	15,240,000	1,429,000
Goodwill		127,952,000	120,553,000	0
Goodwill impairment charges		0	0	0
Unamortized deferred finance costs		10,800,000	$ 6,700,000	9,400,000
Cumulative effect of new accounting principle	[1]				$ 20,106,000
ITC recapture period			5 years
Non-cash deferred revenue recognition		$ 3,457,000	$ 1,320,000	18,238,000
Solar Energy Systems | Minimum
Property, Plant and Equipment [Line Items]
Useful lives of fixed assets		12 years	23 years
Solar Energy Systems | Maximum
Property, Plant and Equipment [Line Items]
Useful lives of fixed assets		28 years	30 years
Wind Power Plants | Minimum
Property, Plant and Equipment [Line Items]
Useful lives of fixed assets		19 years
Wind Power Plants | Maximum
Property, Plant and Equipment [Line Items]
Useful lives of fixed assets		21 years
REC Sales - Incentive Revenue
Property, Plant and Equipment [Line Items]
Payment term		30 days
Accumulated Deficit
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle	[1]				15,221,000
Non-controlling interests
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle	[1]				(308,000)
Redeemable noncontrolling interest
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle					(4,485,000)
ASU 2014-09
Property, Plant and Equipment [Line Items]
Non-cash deferred revenue recognition			$ 16,300,000
ASU 2014-09 | Accumulated Deficit | Renewable Energy Certificates
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle					20,500,000
ASU 2014-09 | Accumulated Deficit | Investment Tax Credits
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle					40,900,000
ASU 2014-09 | Non-controlling interests | Renewable Energy Certificates
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle					300,000
ASU 2014-09 | Redeemable noncontrolling interest | Renewable Energy Certificates
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle					$ 4,500,000
Service Life | Solar Energy Systems | Minimum
Property, Plant and Equipment [Line Items]
Useful lives of fixed assets		8 years
Service Life | Solar Energy Systems | Maximum
Property, Plant and Equipment [Line Items]
Useful lives of fixed assets		36 years
Residential Rooftop Solar Assets
Property, Plant and Equipment [Line Items]
Impairment of renewable energy facilities				$ 1,400,000
Nameplate capacity (MW) | MW				11.4
Solar Segment
Property, Plant and Equipment [Line Items]
Impairment of renewable energy facilities			$ 15,200,000

[1] Represents the effect of the adoption of Accounting Standards Update (“ASU”) No. 2014-09, ASU No. 2016-08, ASU No. 2017-12 and ASU No. 2018-02 as of January 1, 2018.

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Revenue - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Receivable balances related to PPA contracts	$ 104.1	$ 83.5
Contract liabilities	8.4	8.8
Remaining performance obligation	1.8	4.9
Contract liabilities, revenue recognized	$ 3.1	$ 1.3

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Derivatives - Schedule of Gains and Losses on Derivatives not Designated as Hedges (Details) - Derivatives not designated as hedges - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest expense, net | Interest rate swaps
Derivative [Line Items]
(Gain) loss on derivatives	$ 25,790	$ 2,565	$ 3,161
Gain on foreign currency exchange, net | Foreign Currency Contracts
Derivative [Line Items]
(Gain) loss on derivatives	(27,233)	(34,714)	966
Operating revenues, net | Commodity contracts - power
Derivative [Line Items]
(Gain) loss on derivatives	$ 479	$ 3,209	$ (5,117)

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Leases - Cash Flow Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 16,485

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Income Taxes - Deferred Tax Assets (Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating losses and tax credit carryforwards	$ 623,858	$ 587,833
Derivative Liabilities	26,087	33,261
Interest expense limitation carryforward	117,598	67,887
Total deferred tax assets	767,543	688,981
Valuation allowance	(413,884)	(386,336)
Net deferred tax assets	353,659	302,645
Deferred tax liabilities:
Investment in partnership	270,237	221,694
Renewable energy facilities	107,908	30,261
Intangible assets	169,195	229,363
Other	858	176
Total deferred tax liabilities	548,198	481,494
Net deferred tax liabilities	$ 194,539	$ 178,849

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1					$ 212,657	$ 154,515	$ 148,575
Assumed through acquisition					33,143	68,441	0
Accretion expense					15,475	6,866	8,578
Extinguishment upon divestitures					(864)	0	(3,238)
Adjustment related to change in accretion period		$ (500)	$ (500)		27,917	(15,734)	0
Other					0	843	0
Currency translation adjustments					(1,040)	(2,274)	600
Balance as of December 31	$ 287,288			$ 212,657	287,288	212,657	154,515
Adjustment related to change in accretion period		(500)	$ (500)		27,917	(15,734)	0
Accretion expense					15,475	6,866	$ 8,578
Renewable energy facilities in service, net	7,405,461				$ 7,405,461
Scenario, Adjustment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense		3,300
Adjustment related to change in accretion period				(6,300)		(15,700)
Adjustment related to change in accretion period				$ (6,300)		(15,700)
Accretion expense		3,300
Depreciation	$ 3,700	$ 3,700
Decrease in carrying amount of renewable energy facilities						$ (15,700)

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Renewable Energy Facilities - Narrative (Details)		3 Months Ended		12 Months Ended
	Dec. 20, 2019 USD ($) business MW	Dec. 31, 2019 USD ($) business MW	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) business MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 MW
Property, Plant and Equipment [Line Items]
Number of operating projects | business		2		2
Renewable energy facilities, net					$ 6,470,026,000
Gain on sale of renewable energy facilities				$ 2,252,000	0	$ 37,116,000
Impairment of renewable energy facilities				0	15,240,000	1,429,000
REC Sales Agreement
Property, Plant and Equipment [Line Items]
Carrying amount			$ 19,500,000
Fair value of operating project			4,300,000
Impairment of renewable energy facilities			$ 15,200,000		15,200,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Property, Plant and Equipment [Line Items]
Capacity of power (MW) | MW							0.3
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Distributed Generation Facilities
Property, Plant and Equipment [Line Items]
Number of operating projects | business	6
Capacity of power (MW) | MW	6.0
Consideration from sale	$ 9,500,000
Gain on sale of renewable energy facilities	$ 2,300,000	$ 2,300,000
Solar Energy Systems
Property, Plant and Equipment [Line Items]
Depreciation expense				$ 325,100,000	270,400,000	$ 212,600,000
Renewable energy facilities, net					6,464,527,000
Carrying amount					$ 7,298,371,000
Wind Power Plants In Northeast
Property, Plant and Equipment [Line Items]
Number of operating projects | business		2		2
Capacity of power (MW) | MW		160		160
Renewable energy facilities, net		$ 79,400,000		$ 79,400,000

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Fair Value of Financial Instruments - Unobservable Inputs Used in Valuation of Commodity Contracts (Details) - Commodity contracts - power - Level 3 $ in Thousands	Dec. 31, 2019 USD ($) $ / MWh
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Assets | $	$ 59,312
Liabilities | $	$ 0
Measurement Input, Option Volatility | Option model | Minimum
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset, measurement input	0.142
Measurement Input, Forward Price | Discounted cash flow | Minimum
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset, measurement input | $ / MWh	6.30
Measurement Input, Forward Price | Discounted cash flow | Maximum
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative asset, measurement input | $ / MWh	169.30

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The activity on asset retirement obligations for the years ended December 31, 2019, 2018 and 2017 was as follows:

	Year Ended December 31,
(In thousands)	2019		2018		2017
Balance as of January 1	$	212,657	$	154,515	$	148,575
Assumed through acquisition	33,143		68,441		—
Accretion expense	15,475		6,866		8,578
Extinguishment upon divestitures	(864)		—		(3,238)
Adjustment related to change in accretion period1	27,917		(15,734)		—
Other	—		843		—
Currency translation adjustments	(1,040)		(2,274)		600
Balance as of December 31	$	287,288	$	212,657	$	154,515

————

(1)Represents corrections related to changes in the period over which the asset retirement obligations were accreted to their expected future value using the estimate of the future timing of settlement. The correction during the year ended December 31, 2019, recorded in the third quarter, resulted in $27.9 million increase in the carrying amounts of asset retirement obligations and the corresponding renewable energy facilities. The Company also recorded an adjustment to increase the previously reported accretion and depreciation expense by $3.3 million and $3.7 million, respectively, as a result of this change. The Company had recorded an adjustment during the fourth quarter of 2018, which resulted in a $15.7 million reduction in the Company’s asset retirement obligations and the corresponding renewable energy facilities’ carrying amounts as of December 31, 2018. The Company also recorded an adjustment during the fourth quarter of 2018 to reduce previously reported accretion and depreciation expense by $6.3 million as a result of this change. The Company evaluated these adjustments and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company’s consolidated financial statements for any prior period.

The Company did not have any assets that were legally restricted for the purpose of settling the Company’s asset retirement obligations as of December 31, 2019, 2018 and 2017.

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Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2019

Cash and Cash Equivalents [Abstract]

Cash and Cash Equivalents

CASH AND CASH EQUIVALENTS Cash and cash equivalents include all cash balances and money market funds, including restricted cash, with original maturity periods of three months or less when purchased. As of December 31, 2019 and December 31, 2018, cash and cash equivalents included $138.5 million and $177.6 million, respectively, of unrestricted cash held at project-level subsidiaries, which was available for project expenses but not available for corporate use.

Reconciliation of Cash and Cash Equivalents and Restricted Cash as Presented in the Consolidated Statements of Cash Flows

The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the consolidated balance sheets to the total of the same such amounts shown in the consolidated statements of cash flows for the years ended December 31, 2019, 2018 and 2017:

	As of December 31,
(In thousands)	2019		2018		2017
Cash and cash equivalents	$	237,480	$	248,524	$	128,087
Restricted cash, current	35,657		27,784		54,006
Restricted cash - non-current	76,363		116,501		42,694
Cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows	$	349,500	$	392,809	$	224,787

As discussed in Note 10. Long-term Debt, the Company was in default under certain of its non-recourse financing agreements as of the financial statement issuance date for the years ended December 31, 2019 and 2018. As a result, the Company reclassified $11.0 million and $11.2 million, respectively, of long-term restricted cash to current as of December 31, 2019, and 2018, consistent with the corresponding debt classification, as the restrictions that required the cash balances to be classified as long-term restricted cash were driven by the financing agreements.

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Cash and Cash Equivalents (Tables)

12 Months Ended

Dec. 31, 2019

Cash and Cash Equivalents [Abstract]

Schedule of Cash and Cash Equivalents

The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the consolidated balance sheets to the total of the same such amounts shown in the consolidated statements of cash flows for the years ended December 31, 2019, 2018 and 2017:

	As of December 31,
(In thousands)	2019		2018		2017
Cash and cash equivalents	$	237,480	$	248,524	$	128,087
Restricted cash, current	35,657		27,784		54,006
Restricted cash - non-current	76,363		116,501		42,694
Cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows	$	349,500	$	392,809	$	224,787

Schedule of Restricted Cash and Cash Equivalents

The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the consolidated balance sheets to the total of the same such amounts shown in the consolidated statements of cash flows for the years ended December 31, 2019, 2018 and 2017:

	As of December 31,
(In thousands)	2019		2018		2017
Cash and cash equivalents	$	237,480	$	248,524	$	128,087
Restricted cash, current	35,657		27,784		54,006
Restricted cash - non-current	76,363		116,501		42,694
Cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows	$	349,500	$	392,809	$	224,787

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Consolidated Statements of Comprehensive Loss - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net loss		$ (206,585)	$ (153,327)		$ (236,303)
Foreign currency translation adjustments:
Net unrealized gain (loss) arising during the period		15,652	(9,517)		10,300
Reclassification of net realized loss into earnings	[1]	0	0		14,741
Hedging activities:
Net unrealized (loss) gain arising during the period		(42,290)	198		17,612
Reclassification of net realized (gain) loss into earnings		(2,579)	(4,442)	[2]	(2,247)	[2]
Other comprehensive income, net of tax		(29,217)	(13,761)		40,406
Total comprehensive loss		(235,802)	(167,088)		(195,897)
Less comprehensive (loss) income attributable to non-controlling interests:
Net (loss) income attributable to redeemable non-controlling interests		(11,983)	9,209		1,596
Less: Net loss attributable to non-controlling interests		(45,918)	(174,916)		(77,745)
Foreign currency translation adjustments		0	0		8,665
Hedging activities		(624)	(777)		5,992
Comprehensive loss attributable to non-controlling interests		(58,525)	(166,484)		(61,492)
Comprehensive loss attributable to Class A common stockholders		$ (177,277)	$ (604)		$ (134,405)

[1] Represents the reclassification of the accumulated foreign currency translation loss for almost the Company’s entire portfolio of solar power plants located in the United Kingdom, as the Company’s sale of these facilities was completed in the second quarter of 2017 as discussed in Note 3. Acquisitions and Divestitures. The pre-tax amount of $23.6 million was recognized within Gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

[2] epresents the reclassification of the accumulated foreign currency translation loss for almost the Company’s entire portfolio of solar power plants located in the United Kingdom, as the Company’s sale of these facilities was completed in the second quarter of 2017 as discussed in Note 3. Acquisitions and Divestitures.

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(Loss) Earnings Per Share

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

(Loss) Earnings Per Share

(LOSS) EARNINGS PER SHARE

Basic (loss) earnings per share is computed by dividing net (loss) income attributable to Class A common stockholders by the number of weighted average ordinary shares outstanding during the period. Diluted (loss) earnings per share is computed by adjusting basic (loss) income per share for the impact of the equivalent weighted average dilutive common shares outstanding during the period unless the impact is anti-dilutive. Common equivalent shares represent the incremental shares issuable for unvested restricted Common Stock.

Unvested RSAs that contain non-forfeitable rights to distributions are treated as participating securities and are included in the (loss) earnings per share computation using the two-class method. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that would otherwise have been available to common stockholders. This method determines loss per share based on distributions declared on common stock and participating securities (i.e., distributed earnings), as well as participation rights of participating securities in any undistributed earnings. Undistributed losses are not allocated to participating securities since they are not contractually obligated to share in the losses of the Company. The numerator for undistributed (loss) earnings per share is also adjusted by the amount of deemed distributions related to the accretion of redeemable non-controlling interest since the redemption value of the non-controlling interest was considered to be at an amount other than fair value (and was considered a right to an economic distribution that differed from other common stockholders) and as accretion adjustments were recognized in additional paid-in capital and not within net (loss) income attributable to Class A common stockholders.

Basic and diluted (loss) earnings per share of the Company’s Common Stock for the years ended December 31, 2019,

2018 and 2017 was calculated as follows:

	Year Ended December 31,
(In thousands, except per share amounts)	2019		2018		2017
Basic and diluted (loss) earnings per share:
Net (loss) income attributable to Class A common stockholders	$	(148,684)	$	12,380	$	(160,154)
Less: accretion of redeemable non-controlling interest	—		—		(6,729)
Less: cash distributions to Class A shares and participating RSAs	—		—		(285,497)
Undistributed income (loss) attributable to Class A shares	(148,684)		12,380		(452,380)
Weighted average basic and diluted Class A shares outstanding1	213,275		182,239		103,866
Distributed earnings per share	—		—		2.75
Undistributed (loss) earnings per share	(0.70)		0.07		(4.36)
Basic and diluted (loss) earnings per share	$	(0.70)	$	0.07	$	(1.61)

———

(1)The computation of diluted earnings per share of the Company’s Common Stock for the year ended December 31, 2019, excluded the impact of 191,936 potentially dilutive unvested RSUs outstanding at December 31, 2019, because the effect would have been anti-dilutive.

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Subsequent Events

12 Months Ended

Dec. 31, 2019

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

Brookfield Renewable Non-Binding Proposal and Signing of Reorganization Agreement

On January 11, 2020, the Company received an unsolicited and non-binding proposal from Brookfield Renewable Partners L.P., an affiliate of Brookfield, to acquire all of the outstanding shares of Common Stock of the Company, other than the approximately 62% shares held by Brookfield Renewable and its affiliates. The Brookfield Proposal expressly conditioned the transaction contemplated thereby on the approval of a committee of the Board consisting solely of independent directors and the approval of a majority of the shares held by the Company’s stockholders not affiliated with Brookfield Renewable and its affiliates. Following the Company’s receipt of the Brookfield Proposal, the Board formed a Special Committee of non-executive, disinterested and independent directors to, among other things, review, evaluate and consider the Brookfield Proposal and, if the Special Committee deemed appropriate, negotiate a transaction with Brookfield Renewable or explore alternatives thereto. The Board resolutions establishing the Special Committee expressly provided that the Board would not approve the transaction contemplated by the Brookfield Proposal or any alternative thereto without a prior favorable recommendation by the Special Committee. Brookfield Renewable holds an approximately 30% indirect economic interest in TerraForm Power.

On March 16, 2020, pursuant to the Brookfield Proposal, the Company and Brookfield Renewable and certain of their affiliates entered into the Reorganization Agreement for Brookfield Renewable to acquire all of the Company's outstanding shares of Common Stock, other than the approximately 62% currently owned by Brookfield Renewable and its affiliates. Pursuant to the Reorganization Agreement, each holder of a share of Common Stock that is issued and outstanding immediately prior to the consummation of the Transactions will receive, at each such shareholder’s election, 0.381 of a Brookfield Renewable limited partnership unit or of a Class A exchangeable subordinate voting share of Brookfield Renewable Corporation, a Canadian subsidiary of Brookfield Renewable which is expected to be publicly listed as of the consummation of the Transactions. The Special Committee has unanimously recommended that the Company’s unaffiliated shareholders approve the Transactions. Consummation of the Transactions is subject to the non-waivable approval of a majority of the Company’s shareholders not affiliated with Brookfield Renewable, receipt of required regulatory approvals and other customary closing conditions.

Acquisition of 100 MW Concentrated Solar Power Facilities in Spain

On February 11, 2020, TERP Spanish Holdco, S.L.U., a wholly-owned subsidiary of the Company, completed the acquisition of a portfolio of two concentrated solar power facilities located in Spain with a combined nameplate capacity of approximately 100 MW for a total purchase price of approximately €116.8 million (approximately $127.5 million as of the date of the acquisition). These facilities are regulated under the Spanish framework for renewable power, with approximately 19 years of remaining regulatory life. The Company is in the process of evaluating the acquisition accounting considerations, including the determination of the acquisition of a business or a group of assets and the initial purchase price allocation.

First Quarter 2020 Distributions

On March 16, 2020, the Company’s Board of Directors declared a cash distribution with respect to Common Stock of $0.2014 per share. The distribution is payable on March 31, 2020 to stockholders of record as of March 27, 2020.

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net loss	$ (206,585,000)	$ (153,327,000)	$ (236,303,000)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, accretion and amortization expense	434,110,000	341,837,000	246,720,000
Amortization of favorable and unfavorable rate revenue contracts, net	39,940,000	38,767,000	39,576,000
Loss on modification and extinguishment of debt, net	26,953,000	1,480,000	81,099,000
Gain on sale of renewable energy facilities	(2,252,000)	0	(37,116,000)
Impairment of renewable energy facilities	0	15,240,000	1,429,000
Loss on disposal of renewable energy facilities	15,483,000	6,231,000	5,828,000
Amortization of deferred financing costs, debt discounts, and premiums	14,224,000	11,009,000	23,729,000
Unrealized (gain) loss on interest rate swaps	(4,658,000)	(13,116,000)	2,425,000
(Reductions) charges to allowance for doubtful accounts, net	(4,239,000)	4,510,000	339,000
Unrealized loss on commodity contract derivatives, net	14,036,000	4,497,000	6,847,000
Recognition of deferred revenue	(3,457,000)	(1,320,000)	(18,238,000)
Stock-based compensation expense	492,000	257,000	16,778,000
Gain on foreign currency exchange, net	(11,480,000)	(12,899,000)	(5,583,000)
Deferred taxes	6,983,000	(14,891,000)	(19,911,000)
Other, net	231,000	0	254,000
Changes in assets and liabilities, excluding the effect of acquisitions and divestitures:
Accounts receivable	(8,310,000)	12,569,000	(2,939,000)
Prepaid expenses and other current assets	975,000	(5,512,000)	803,000
Accounts payable, accrued expenses and other current liabilities	(17,000,000)	(18,976,000)	(42,537,000)
Due to affiliates, net	4,215,000	3,023,000	3,968,000
Other, net	28,783,000	33,822,000	29,000
Net cash provided by operating activities	328,444,000	253,201,000	67,197,000
Cash flows from investing activities:
Capital expenditures	(21,184,000)	(22,445,000)	(8,392,000)
Proceeds from the settlement of foreign currency contracts, net	29,806,000	47,590,000	0
Proceeds from divestiture of renewable energy facilities, net of cash and restricted cash disposed	10,848,000	0	183,235,000
Proceeds from energy rebate and reimbursable interconnection costs	5,117,000	8,733,000	25,679,000
Payments to acquire businesses, net of cash and restricted cash acquired	(731,782,000)	(886,104,000)	0
Payments to acquire renewable energy facilities from third parties, net of cash and restricted cash acquired	(73,682,000)	(8,315,000)	0
Proceeds from insurance reimbursement	0	1,543,000	0
Other investing activities	6,244,000	0	5,750,000
Net cash (used in) provided by investing activities	(774,633,000)	(858,998,000)	206,272,000
Cash flows from financing activities:
Proceeds from issuance of Class A common stock, net of issuance costs	298,767,000	650,000,000	0
Purchase of treasury stock	(8,353,000)	0	0
Revolver draws	492,500,000	679,000,000	265,000,000
Proceeds from the Sponsor Line - affiliate	0	86,000,000	0
Repayments of the Sponsor Line - affiliate	0	(86,000,000)	0
Debt financing fees paid	(37,597,000)	(9,318,000)	(29,972,000)
Sale of membership interests and contributions from non-controlling interests	6,356,000	7,685,000	6,935,000
Purchase of membership interests and distributions to non-controlling interests	(30,509,000)	(29,163,000)	(31,163,000)
Net SunEdison investment	0	0	7,694,000
Due to affiliates, net	0	4,803,000	(8,869,000)
Cash distributions to Class A common stockholders	(171,503,000)	(135,234,000)	(285,497,000)
Payments to terminate interest rate swaps	(18,600,000)	0	0
Recovery of related party short-swing profit	0	2,994,000	0
Other financing activities	0	0	1,085,000
Net cash provided by (used in) financing activities	406,812,000	782,501,000	(789,513,000)
Net (decrease) increase in cash, cash equivalents and restricted cash	(39,377,000)	176,704,000	(516,044,000)
Net change in cash, cash equivalents and restricted cash classified within assets held for sale	0	0	54,806,000
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(3,932,000)	(8,682,000)	3,188,000
Cash, cash equivalents and restricted cash at the beginning of the year	392,809,000	224,787,000	682,837,000
Cash, cash equivalents and restricted cash at the end of the year	349,500,000	392,809,000	224,787,000
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	294,145,000	250,734,000	260,685,000
Cash paid for income taxes	2,062,000	430,000	0
Schedule of non-cash activities:
Right-of-use assets recognized under Topic 842	262,142,000
Right-of-use liabilities recognized under Topic 842	256,015,000
Additions to renewable energy facilities in accounts payable and accrued expenses	1,455,000	4,000,000	1,622,000
Write-off of payables to SunEdison	0	0	15,677,000
Adjustment to ARO related to change in accretion period	27,917,000	(15,734,000)	0
Issuance of class A common stock to affiliates for settlement of litigation	0	881,000	0
ARO assets and obligations from acquisitions	33,143,000	68,441,000	0
Long-term debt assumed in connection with acquisitions	151,713,000	1,932,743,000	0
Senior Notes due 2030 | Secured Debt
Cash flows from financing activities:
Proceeds from Senior Notes due	700,000,000	0	0
Senior Notes Due 2025
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on modification and extinguishment of debt, net	22,827,000	0	0
Senior Notes Due 2025 | Secured Debt
Cash flows from financing activities:
Repayment of Senior Notes	(300,000,000)	0	0
Senior Notes due 2023 | Secured Debt
Cash flows from financing activities:
Proceeds from Senior Notes due	0	0	494,985,000
Old Senior Notes Due in 2023 | Secured Debt
Cash flows from financing activities:
Repayment of Senior Notes	0	0	(950,000,000)
Senior Notes prepayment penalties	(18,366,000)	0	(50,712,000)
Senior Notes due 2028
Cash flows from financing activities:
Proceeds from Senior Notes due	0	0	692,979,000
Revolver
Cash flows from financing activities:
Revolver payments	(869,500,000)	(362,000,000)	(205,000,000)
Old Revolver
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on modification and extinguishment of debt, net	0	0	8,822,000
Cash flows from financing activities:
Revolver payments	0	0	(552,000,000)
Term Loan
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on modification and extinguishment of debt, net	4,006,000	1,480,000	0
Term Loan | Secured Debt
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on modification and extinguishment of debt, net	4,000,000.0	1,500,000
Cash flows from financing activities:
Proceeds from Term Loan and non-recourse long-term debt	0	0	344,650,000
Senior Notes prepayment penalties	(343,875,000)	0	0
Principal payments and prepayments on non-recourse long-term debt	(2,625,000)	(3,500,000)	0
Non-Recourse Long-Term Debt
Cash flows from financing activities:
Proceeds from Term Loan and non-recourse long-term debt	792,216,000	236,251,000	79,835,000
Principal payments and prepayments on non-recourse long-term debt	(557,099,000)	(259,017,000)	(569,463,000)
Bridge Facility | Secured Debt
Cash flows from financing activities:
Proceeds from the Bridge Facility	$ 475,000,000	$ 0	$ 0