UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 _____________________________________________________________________________

FORM 10-K

 _____________________________________________________________________________

(Mark One)

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

For the Fiscal Year ended December 31, 2018

OR

o 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	Name of Exchange on Which Registered
Common Stock, Class A, par value $0.01	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  o    No  x

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  o    No  x

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

Indicate by check mark whether the registrant has submitted electronically 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  x    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

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	x	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	o
Emerging growth company	o

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

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

As of June 30, 2018, 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 Global Select Market on such date), was approximately $0.9 billion.

As of February 28, 2019, there were 209,141,720 shares of Class A common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive proxy statement relating to its 2019 annual meeting of stockholders (the “2019 Proxy Statement”) are incorporated by reference into Part III of this Form 10-K where indicated. The 2019 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	6
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	46
Item 4.	Mine Safety Disclosures	46
Part II. Financial Information
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	48
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	73
Item 8.	Financial Statements and Supplementary Data	75
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	75
Item 9A.	Controls and Procedures	75
Item 9B.	Other Information	78
Part III. Executive Information
Item 10.	Directors, Executive Officers and Corporate Governance	78
Item 11.	Executive Compensation	78
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
Item 13.	Certain Relationships and Related Transactions, and Director Independence	78
Item 14.	Principal Accounting Fees and Services	78
Part IV. Exhibits
Item 15.	Exhibits, Financial Statement Schedules	79
Item 16.	Form 10-K Summary	79

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This communication 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 the Company expects or anticipates will occur in the future are forward-looking statements. They may include estimates of expected cash available for distribution, dividend 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 dividends 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 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 on acceptable prices and terms, including as our offtake agreements expire;

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

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

• pending and future litigation;

• our ability to successfully integrate projects we acquire from third parties, including Saeta Yield S.A.U., and our ability to realize the anticipated benefits from such acquisitions;

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

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

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

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

• 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;

• our ability to identify or consummate any future acquisitions, including those identified by Brookfield;

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

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

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

The Company disclaims 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 on Form 10-K, as well as additional factors we may describe from time to time in 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:

Adjusted EBITDA	Adjusted EBITDA is defined as net income (loss) plus depreciation, accretion and amortization, non-cash general and administrative costs, 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 cash distributions paid to non-controlling interests in our renewable energy facilities, if any, (ii) minus annualized scheduled interest and project level amortization payments in accordance with the related borrowing arrangements, (iii) 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, (iv) plus or minus operating items as necessary to present the cash flows we deem representative of our core business operations. As compared to the preceding period, we revised our definition of CAFD to (i) exclude adjustments related to deposits into and withdrawals from restricted cash accounts, required by project financing arrangements, (ii) replace sustaining capital expenditures payment made in the year with the average annualized long-term sustaining capital expenditures to maintain reliability and efficiency of our assets, and (iii) annualized debt service payments. We revised our definition as we believe it provides a more meaningful measure for investors to evaluate our financial and operating performance and ability to pay dividends.   For items presented on an annualized basis, we will present actual cash payments as a proxy for an annualized number until the period commencing January 1, 2018.
GWh	Gigawatt hours
HLBV	Hypothetical Liquidation at Book Value
IDRs	Incentive Distribution Rights
ISDA	International Swaps and Derivatives Association, Inc.
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.
O&M	Operations and maintenance
PPA	As applicable, Power Purchase Agreement, energy hedge contract and/or REC or SREC contract
PTC	Production tax credit
REC	Renewable energy certificate or SREC
Renewable energy facilities	Solar generation facilities and wind power plants
SREC	Solar renewable energy certificate
U.S. GAAP	Accounting principles generally accepted in the United States

In this Annual Report on Form 10-K, 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, Inc. (“TerraForm Power” and, together with its subsidiaries, the “Company”) acquires, owns and operates solar and wind assets in North America and Western Europe. We are the owner and operator of a 3,738 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 $350 billion in assets under management. Affiliates of Brookfield held approximately 65% of TerraForm Power’s Class A common stock as of December 31, 2018.

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 dividend, which we intend to grow at 5 to 8% per annum, that is backed by stable cash flows.

TerraForm Power 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.

Our principal executive offices are located at 200 Liberty Street, 14th Floor, New York, New York10281, 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 on Form 10-K and does not constitute part of this Annual Report on Form 10-K.

6

The diagram below is a summary depiction of our organizational and capital structure as of December 31, 2018:

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(1) As of December 31, 2018, there were 209,141,720 Class A shares of TerraForm Power outstanding. Orion US Holdings 1 L.P. (“Orion Holdings”) and BBHC Orion Holdco L.P., each controlled affiliates of Brookfield, together own an aggregate 65% of our shares outstanding.

(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. (the “Brookfield IDR Holder”) holds all of the IDRs of Terra LLC. Brookfield IDR Holder is an indirect wholly owned subsidiary of Brookfield. 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 borrowing capacity as of December 31, 2018. As of December 31, 2018, there were $377.0 million of revolving loans and $99.5 million of letters of credit outstanding under the Revolver, with availability of $123.5 million as of such date.

(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.

7

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 a 3,738 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 dividends 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 purposes. We expect to generate this return with a regular dividend, 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:

We focus on sourcing off-market transactions at more attractive valuations than auction processes. Our successful acquisition of Saeta provides us with a European Platform and is an example of one such opportunity. 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, who sold its equity interest in this warehouse vehicle to an unaffiliated third party in 2017.

• Margin Enhancements:

We believe there is significant opportunity to enhance our cash flow through optimizing the performance of our existing assets. As our recently announced long-term service agreements (collectively, the “LTSA”) with an affiliate of General Electric 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. We are currently seeking to execute similar agreements to optimize the performance of our North American solar and European wind fleets.

• 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 power, property, infrastructure and private equity. Brookfield has approximately $350 billion of assets under management of which $47 billion are renewable power assets. This renewable power portfolio represents approximately 17,400 MW of generation capacity in 15 countries. It also employs over 2,500 individuals with extensive operating, development and power marketing capabilities and has a demonstrated ability to deploy capital in a disciplined manner, having developed or acquired 13,200 MW of renewable generation capacity since 2012.

8

Sponsorship Arrangements

On October 16, 2017, a wholly-owned subsidiary of Orion Holdings merged with 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, BRP Energy Group L.P., Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P., Brookfield Global Renewable Energy Advisor Limited, Terra LLC and Terra Operating LLC, pursuant to which Brookfield and certain of its affiliates provide certain management and 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, during the term of the agreement, TerraForm Power and its subsidiaries serve as the primary vehicle through which Brookfield and its affiliates will acquire operating solar and wind assets in certain countries in North America and Western Europe, and Brookfield grants TerraForm Power a right of first offer 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 and the relationship between such members of the Sponsor Group and TerraForm Power and its controlled affiliates.

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 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 of Directors (the “Board”) is currently set at seven members, of whom four are designated by Brookfield and three are independent. Under the terms of the Sponsorship Transaction, Brookfield appoints our Chief Executive Officer, Chief Financial Officer and General Counsel. These three executive officers are not employees of the Company 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 our independent directors. The Conflicts Committee considers, among other things, matters in which a conflict of interest exists between our Company 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.

9

Changes within Our Portfolio

The following table provides an overview of the changes within our portfolio from December 31, 2017 through December 31, 2018:

		Nameplate Capacity (MW)
	Facility Type		Number of Sites	Weighted Average Remaining Duration of PPA (Years)1
Description
Total Portfolio as of December 31, 2017		2,698	533	14
Acquisition of Saeta	Solar and Wind	1,027	32	14
Acquisition of TEG assets	Solar	6	6	11
Acquisition of Tinkham Hill Expansion assets2	Solar	3	1	20
Acquisition of IFM assets	Solar	4	3	19
Total Portfolio as of December 31, 2018		3,738	575	13

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(1) Represents weighted-average remaining term of power purchase agreements (“PPAs”) and calculated as of December 31, 2017 and December 31, 2018, respectively.

(2) This asset is expected to achieve its commercial operation date during the second quarter of 2019.

Our Portfolio

Our current portfolio consists of renewable energy facilities located in the United States (including Puerto Rico), Canada, Spain, Chile, Portugal, the United Kingdom and Uruguay with a combined nameplate capacity of 3,738 MW as of December 31, 2018. These renewable energy facilities generally have long-term PPAs with creditworthy counterparties. As of December 31, 2018, on a weighted average basis (based on MW), our PPAs had a remaining life of 13 years and our 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, 2018:

Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Weighted Average Remaining Duration of PPA (Years)1
Solar Distributed Generation:
CD DG Portfolio	U.S.2	77.8	42	14
DG 2015 Portfolio 2	U.S.2	48.1	30	17
U.S. Projects 2014	U.S.2	45.4	41	16
DG 2014 Portfolio 1	U.S.2	44.0	46	16
TEG	U.S.2	39.9	62	10
Hudson Energy Solar	U.S.2	25.2	67	11
MA Solar	Massachusetts	21.1	4	25
Summit Solar Projects	U.S.2	19.6	50	8
U.S. Projects 2009-2013	U.S.2	15.2	73	17
SUNE XVIII	U.S.2	16.1	21	11
California Public Institutions	California	13.5	5	14
Enfinity	U.S.2	13.2	15	15
MA Operating	Massachusetts	12.2	4	12
Duke Operating	North Carolina	10.0	3	13
SunE Solar Fund X	U.S.2	8.8	12	15
Summit Solar Projects	Ontario	3.8	7	15
MPI	Ontario	4.7	13	13
Tinkham Hill Expansion	Massachusetts	2.5	1	20

10

Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Weighted Average Remaining Duration of PPA (Years)1
Total Solar Distributed Generation		421.1	496	15
Solar Utility:
Mount Signal	California	265.8	1	20
Amanecer Solar CAP	Chile	101.6	1	15
Regulus Solar	California	81.6	1	16
Blackhawk Solar Portfolio	U.S.2	72.8	10	18
North Carolina Portfolio	North Carolina	26.4	4	11
Northern Lights	Ontario	25.4	2	15
Atwell Island	California	23.5	1	19
Marsh Hill	Ontario	18.5	1	16
SunE Perpetual Lindsay	Ontario	15.5	1	16
Nellis	Nevada	14.0	1	9
Norrington	U.K.	11.1	1	10
Alamosa	Colorado	8.2	1	9
CalRENEW-1	California	6.3	1	16
Total Solar Utility		670.7	26	17

11

Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Weighted Average Remaining Duration of PPA (Years)1
Wind Utility:
South Plains I	Texas	200.0	1	11
California Ridge	Illinois	217.1	1	14
Bishop Hill	Illinois	211.4	1	14
Rattlesnake	Texas	207.2	1	9
Prairie Breeze	Nebraska	200.6	1	20
Cohocton	New York	125.0	1	2
Stetson I & II	Maine	82.5	2	2
Raleigh	Ontario	78.0	1	12
Rollins	Maine	60.0	1	13
Carapé I	Uruguay	52.3	1	20
Carapé II	Uruguay	43.1	1	17
Mars Hill	Maine	42.0	1	1
Sheffield	Vermont	40.0	1	9
Steel Winds I & II	New York	35.0	2	1
Bull Hill	Maine	34.5	1	9
Kaheawa Wind Power I	Hawaii	30.0	1	7
Kahuku	Hawaii	30.0	1	12
Penamacor 3B	Portugal	25.2	1	10
Sabugal	Portugal	25.2	1	10
Kaheawa Wind Power II	Hawaii	21.0	1	14
Penamacor 1	Portugal	20.0	1	10
Penamacor 2	Portugal	20.0	1	10
Penamacor 3A	Portugal	14.7	1	10
Penamacor 3B Ext1	Portugal	14.7	1	10
Sabugal Ext2	Portugal	12.0	1	10
Penamacor 3B Ext 2	Portugal	8.0	1	10
Sabugal Ext1	Portugal	4.0	1	10
Total Wind Utility		1,853.5	29	11
Regulated Solar and Wind
Seron 1	Spain	50.0	1	11
Tesosanto	Spain	50.0	1	15
Extresol 1	Spain	49.9	1	16
Extresol 2	Spain	49.9	1	17
Extresol 3	Spain	49.9	1	19
Machasol 2	Spain	49.9	1	18
Serrezuela	Spain	49.9	1	20
Abuela Santa Ana	Spain	49.5	1	12
Montegordo	Spain	48.0	1	12
Santa Catalina Cerro Negro	Spain	41.5	1	14
Viudo I	Spain	40.0	1	14
Sierra de las Carbas	Spain	40.0	1	12
Tijola	Spain	36.8	1	11
Colmenar 2	Spain	30.0	1	10
La Noguera	Spain	29.9	1	12
Viudo II	Spain	26.0	1	14
Los Isletes	Spain	25.3	1	12

12

Facility Category / Portfolio	Location	Nameplate Capacity (MW)	Number of Sites	Weighted Average Remaining Duration of PPA (Years)1
Las Vegas	Spain	23.0	1	11
La Caldera	Spain	22.5	1	12
Valcaire	Spain	16.0	1	15
Seron 2	Spain	10.0	1	11
IFM	Spain	4.4	3	19
Total Regulated Solar and Wind		792.4	24	14
Total Renewable Energy Facilities		3,737.7	575	13

———

(1) Calculated as of December 31, 2018.

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

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

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

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

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

• TEG: Arizona, California, Connecticut, Massachusetts, New Jersey and Pennsylvania

• Hudson Energy Solar: Massachusetts, New Jersey and Pennsylvania

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

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

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

• Enfinity: Arizona, California and Ohio

• SunE Solar Fund X: California, Maryland and New Mexico

• Blackhawk Solar Portfolio: Utah, Florida, Nevada and California

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 winter months result in less irradiation, the electricity generated 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 majority of our solar power plants are located in the Northern Hemisphere, we expect our 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 revenue 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 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 profiles, 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.

We do not expect seasonality to have a material effect on our ability to pay a regular dividend. We intend to mitigate the effects of any seasonality that we experience by reserving a portion of our cash available for distribution and otherwise maintain sufficient liquidity in order to, among other things, facilitate the payment of dividends 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 providers of distributed generation. We compete with other renewable energy developers, independent power producers, financial investors, utilities and other providers of distributed generation based on our cost of capital, development expertise, pipeline, global footprint and brand

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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 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 are exempt from the books and records access provisions of PUHCA, and most are exempt from state organizational and financial regulation of electric utilities. 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 ratemaking and certain other regulatory provisions of the Federal Power Act, as amended (“FPA”).

All of the renewable energy facility companies that we own outside of the United States are Foreign Utility Companies, as defined in PUHCA. They are exempt from state organizational and financial regulation of electric utilities and from most provisions of PUHCA and FPA.

We own a number of renewable energy facilities in the United States that are 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 facilities to sell electricity, capacity and ancillary services at wholesale or 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. FERC requires market based rate holders to make additional 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.

Under Section 203 of the FPA (“FPA Section 203”), prior authorization by FERC is generally required for any direct or indirect acquisition of control over, or merger or consolidation with, a “public utility,” facilities subject to FPA jurisdiction,

or in certain circumstances an “electric utility company,” as such terms are used for purposes of FPA Section 203. All of our renewable energy facilities that sell their output at wholesale in the continental U.S. (except in Texas) and our subsidiary Evergreen Gen Lead, LLC (which owns electric transmission facilities), are public utilities, and all are electric utility companies (including those in Texas) for the purposes of FPA Section 203. FERC generally presumes that the acquisition of direct or indirect voting power of 10% or more in an entity results in a change in control of such entity. Transfers of transmission facilities associated with our electric generation facilities or the whole of any such generation facility 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 a public utility, the parent holding company of a public utility or an electric utility company, or to an acquirer of the voting securities of such holding company or its public utility or electric utility company subsidiaries.

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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, the Company is 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 its 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 single owner has more than 1,500 MW of reliability assets under its control in a single connection and expand again once the owner has more than 3,000 MW under construction. Such future changes in our regulatory status or the makeup of our fleet could require it to incur materially higher costs which could have a material adverse impact on its 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 the sale of electricity by us. 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.

Spain

The legal framework applicable to the renewable energy facilities located in Spain includes the following laws and ministerial orders promulgated thereunder:

• Royal Decree-Law 9/2013, dated July 12, 2013 (the “Royal Decree-Law 9/2013”), containing emergency measures to guarantee the financial stability of the electricity system;

• Law 24/2013, dated December 26, 2013 (the “Electricity Act”); and

• Royal Decree 413/2014, dated June 6, 2014 (the “Royal Decree 413/2014”), regulating electricity production from renewable energy sources.

The Electricity Act recognizes some rights for producers with facilities that use renewable energy sources, such as priority in access to offtakers and transmission and distribution networks and entitlement to the recovery of certain costs. Under the Electricity Act, renewable energy electricity producers are required to offer to sell their energy through the market operator, to maintain the plant’s planned production capacity (including power lines connecting to transmission or distribution networks) and to contract and pay fees to transmission and distribution companies in order for their power to be fed into the grid.

The Electricity Act and Royal Decree 413/2014 require electricity generation facilities to be entered on the official register of electricity production plants maintained by the Ministry for the Ecological Transition. To receive cost reimbursement, renewable energy facilities are required under the Electricity Act and Royal Decree 413/2014 to be listed on a new register entitled the Specific Payment System Register, Registro de Regimen Retributivo Especifico. Unregistered plants will only receive the pool price.

Royal Decree-Law 9/2013 introduced a change in the payment system applicable to new and existing electricity production facilities using renewable energy sources to guarantee the financial stability of the electric system. The purpose of Royal Decree-Law 9/2013, which became effective on July 14, 2013, was to adopt a series of measures to ensure the stability of the electric system and to combat the shortfalls between electricity system revenues and costs, referred to as the tariff deficit. Royal Decree-Law 9/2013 established an entirely new remuneration system, abolishing the remuneration system based on a regulated tariff applicable to electricity production facilities using renewable energy sources (including facilities in operation at the time that Royal Decree-Law 9/2013 became effective).

Prior to the adoption of Royal Decree-Law 9/2013, electricity production facilities using renewable energy sources received a feed-in tariff tied to their electricity produced according to their power output. According to Royal Decree 413/2014, producers receive: (i) the pool price for the power they produce and (ii) a payment based on the standard investment cost for

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each type of plant (which is not tied to the amount of power they generate). This payment, based on investment (in €/MW of installed capacity), is supplemented (in cases of technologies with running costs in excess of the pool price) with an operating payment (in €/MWh produced).

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, 2019 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, and 40% (of the amount otherwise available) in the case of a facility for which construction begins in 2019. 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.

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. Further, 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

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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 also have adopted procurement requirements for renewable energy production. There are 29 states that have adopted 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 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 dividends 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 dividend 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 Saeta, that to some extent rely on governmental incentives in international jurisdictions.

In Spain, under Royal Decree 413/2014, renewable electricity producers receive the merchant price for the power they produce and 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 investment. The reasonable return is calculated as the average yield on Spanish government 10-year bonds on the secondary market in a 24-month period preceding the new regulatory period, plus a premium based on the financial condition of the Spanish electricity system and prevailing economic conditions. The amount of the return is recalculated at the end of each six-year regulatory period. The first regulatory period began on July 14, 2013, and will end on December 31, 2019. The Spanish government initiated its review of the rates of return on investment and operations with the publication of a draft law on December 28, 2018. The next regulatory period will begin on January 1, 2020.

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 recent change in government in Ontario makes it unlikely that historic levels of support for renewables will be sustained in the near term.

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.

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Business Segments

We have three reportable segments: (i) Solar, (ii) Wind and (iii) Regulated Solar and Wind. These segments, which constitute 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. Our reportable segments are comprised 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 in deciding how to allocate resources. Portugal Wind, Uruguay Wind, and the Regulated Spanish Solar and Wind segments are new operating segments that were added during the second quarter of 2018, and include all of Saeta’s operations. Consequently, the Company’s operating segments consist of: (i) Distributed Generation, North America Utility and International 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 Regulated Spanish Solar and Wind operating segments, which are aggregated within the Regulated Solar and Wind reportable segment. These operating segments have been aggregated into reportable segments as they have similar economic characteristics and meet all applicable aggregation criteria. We also have corporate expenses which include general and administrative expenses, acquisition costs, interest expense on corporate-level indebtedness, stock-based compensation and depreciation, accretion and amortization expense. All net operating revenues for the years endedDecember 31, 2018, 2017 and 2016 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.

Customer Concentration

For the year ended December 31, 2018, TerraForm Power earned an aggregate of $186.7 million from the Spanish Electricity System, including $127.9 million from the Comisión Nacional de los Mercados y la Competencia (“CMNC”), which represented 16.7% of our 2018 consolidated operating revenues. The role of the CMNC is to collect funds payable, mainly from the tariffs to end user customers, and is responsible for the calculation and the settlement of regulated payments. We believe this concentration risk 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. Other than the CMNC in Spain, there is no other single customer from which we generated more than 10% of our revenues for the year ended December 31, 2018. In California, where a portion of our solar generation fleet is located, we generated certain revenues from three public utilities located in the state. These three public utilities, in aggregate, accounted for approximately 13.6% of our consolidated operating revenues for the year ended December 31, 2018.

Employees

As of December 31, 2018, we had 177 full-time employees, the majority of whom were located in the United States. The governance agreements entered into between the Company 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 the Company and their services are provided pursuant to the Brookfield MSA.

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 and 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 material with, or furnish it 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:

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•Audit Committee Charter;

•Conflicts Committee Charter;

•Nominating and Corporate Governance Committee Charter;

•Board of Directors Charter;

•Code of Business Conduct and Ethics;

•Anti-Bribery and Corruption Policy;

•Health, Safety, Security & 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 to 200 Liberty Street, 14th Floor, New York, New York10281.

The information on our website is not incorporated by reference into this Annual Report on Form 10-K and does not constitute part of this Annual Report on Form 10-K.

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 on Form 10-K 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 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 have based our decisions about which sites to acquire and operate in part on the findings of long-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, including 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.

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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 more costly;

• 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 power purchase agreements with public utilities or commercial, industrial 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. 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, 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. One of our offtake purchasers, a public utility company based in California, filed for federal bankruptcy protection in January 2019. Our exposure to this particular offtake purchaser is less than 1% of our portfolio on a MW and revenue basis. While we believe the financial impact to our business will be limited, there can be no assurance of the actual impact of this bankruptcy, or any future bankruptcies of any of our offtake purchasers (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 PPAs could be time consuming or costly and could involve 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 allow the offtake purchaser to purchase all or a portion of the applicable renewable energy facility 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 countries 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.

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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 solar 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 solar 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 clean 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, 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, 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. Further, 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

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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.

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 solar 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, such as Arizona, 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 could be implemented in other states, which 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, 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.

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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 and other environmental attributes of our facilities. These RECs 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 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 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. If our renewable energy facilities do not generate the amount of electricity required to earn the RECs or other environmental attributes sold under such forward contracts or if for any reason the electricity we generate does not produce RECs or other environmental attributes for a particular state, we may be required to make up the shortfall of RECs 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 as credit support for these obligations. Additionally, forward contracts for REC 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 or other environmental attributes is limited by market conditions, leaving us exposed to the risk of falling prices for RECs 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 may adversely affect the demand for, or availability of, RECs 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, regulatory proceedings and other disputes, which require significant attention from our management, which involve exposure to legal liability and may result in significant damage awards and which may relate to the operations of our renewable energy facilities.

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, as more fully described in Note 18. Commitments and Contingencies to our consolidated financial statements, included in this Annual Report on Form 10-K. 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. We filed a motion to dismiss the amended complaint on July 5, 2016, which was denied on February 6, 2018. In January 2019, a pre-trial schedule was agreed between Terra LLC and the plaintiffs and approved by the Court that provided for fact discovery and depositions. We believe the First Wind Sellers’ allegations 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 such a claim.

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. In addition, we are named as defendants from time to time in other lawsuits and regulatory actions relating to our business, some of which may claim significant damages.

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

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regulatory proceedings, such proceedings are often expensive, lengthy and disruptive to normal business operations and require significant attention from our management. 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 and investigations.

In the past, companies that have experienced volatility in the market price of their stock 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, which could result in substantial costs and divert our management’s attention from other business concerns, and have a material adverse effect on our business.

We may not be able to successfully integrate the operations, technologies and personnel of our European Platform, and to establish appropriate accounting controls in respect of our European Platform, which could result in a material adverse impact on our business.

We believe the acquisition of Saeta, which established our European Platform, will be accretive to cash available for distribution to our stockholders on a per share basis. However, to realize the anticipated benefits of our acquisition, our business and our European Platform’s business must be successfully combined. We may fail to realize these anticipated benefits as a result of our inability to successfully integrate the operations, technologies and personnel of our European Platform into our business for a variety of reasons, including the following:

• failure to successfully manage relationships with existing Saeta counterparties;

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

• 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 framework agreement and LTSAs with General Electric.

In August 2018, we executed an 11-year framework agreement with an affiliate of General Electric to provide us with long-term service agreements (collectively, the “LTSAs”) for turbine operations and maintenance as well as other balance of plant services for our 1.6 GW North American wind fleet. The LTSAs are expected to improve and optimize turbine performance in order to increase production from our wind fleet, as well as provide cost savings to us. However, we may not fully realize these anticipated benefits or at all. For example, we may not achieve increased production from our wind fleet or realize any of the expected cost savings from the LTSAs. We also may not receive the support of our stakeholders, some of whom must provide consents in connection with the implementation of the LTSAs.

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

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, 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 dividends to holders of our Class A common stock at forecasted levels or at all. Incomplete performance by us or third parties under O&M agreements may increase the risks of operational or mechanical failure of our facilities. 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

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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. 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 our business financial condition, results of operations and cash flows.

Developers of 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.

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.

We may incur unexpected expenses if the suppliers of components in 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. For example, a portion of our solar power plants utilize modules made by SunEdison and certain of its affiliates that were debtors in the SunEdison Bankruptcy (as defined in Note 1. Nature of Operations and Organization to our consolidated financial statements). Our business, financial condition, results of operations and cash flows could be materially adversely affected if we cannot make claims under warranties covering our renewable energy facilities.

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

Our concentrated solar 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 at any of our these 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 damage to the environment or damages and harm to third parties or the public, which could expose us to significant liability. Repairing any such failure could require us to expend significant amounts of capital and other resources.

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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 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, the proceeds of such insurance, warranties or performance guarantees may not cover our lost revenues, increased expenses or liquidated damages 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. Further, 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.

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, which could impair our ability to execute favorable financial hedges in the future.

Certain of our wind power plants are party to financial swaps or other hedging arrangements. We may also acquire additional assets with similar hedging arrangements in the future. Under the terms of the existing financial swaps, certain wind power plants are not obligated to physically deliver or purchase electricity. Instead, they receive payments for specified quantities of electricity based on a fixed-price and are obligated to pay the counterparty the market price for the same quantities of electricity. These financial swaps cover quantities of electricity that we estimated are highly likely to be produced. As a result, gains or losses under the financial 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 covered by the associated swap contract, we could incur significant losses if electricity prices in the market rise substantially above the fixed-price provided for in the swap. If a wind power plant generates more electricity than is contracted in the swap, 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 of these financial or hedging arrangements are financially 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

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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 financial hedges at prices that are higher than the prices at which we are able to sell physical power from the applicable facility, thus reducing the effectiveness of the swap hedges.

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 portion of our revenues and incur a portion of our expenses in currencies other than U.S. dollars. The portion of our revenues generated in currencies other than U.S. dollars increased substantially upon our acquisition of our European Platform and may also increase in the future if we 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, Canadian dollar, British pound sterling and other currencies.

Additionally, although a portion of our revenues and expenses are denominated in foreign currency, any dividends we pay will be denominated in U.S. dollars. The amount of U.S. dollar denominated dividends paid to our holders of our Class A 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 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 dividends paid by us to holders of our Class A 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 Unites 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, from factors such as political conflict, 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 could 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.

Unforeseen political events in markets where we own and operate assets and may look to for further growth of our businesses may create economic uncertainty that has a negative impact on our financial performance. Such uncertainty could cause disruptions to our businesses, including affecting the business of and/or our relationships with our customers and suppliers, as well as altering the relationship among tariffs and currencies. Disruptions and uncertainties could adversely affect our financial condition, operating results and cash flows. In addition, political outcomes in the market in which we operate may also result in legal uncertainty and potentially divergent national laws and regulation, which can contribute to general economic

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uncertainty. Economic uncertainty impacting us and our operations and investments could be exacerbated by near-term political events, including those in the markets in which we operate and elsewhere.

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 ratemaking and certain other regulatory provisions of the FPA, from the books and records access provisions of PUHCA, and from state organizational and financial regulation of electric utilities.

The immediate owners of certain of our utility scale plants are EWGs, as defined under PUHCA, which exempts each EWG and us (for purposes of our ownership of each such company) from the federal books and access provisions of 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 rates and their issuances of securities. 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.

The failure of our QFs to maintain QF status may result in their and 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.

In particular, the EWGs, and any project companies that own or operate our QFs that obtain market based rate authority from FERC under the FPA 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.

Revenues in our solar and wind assets in Spain are mainly defined by regulation and some of the parameters defining the remuneration are subject to review every three and six years.

In 2013, the Spanish government modified regulations applicable to renewable energy assets, including solar and wind power. According to Royal Decree 413/2014, renewable electricity producers in Spain receive: (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 (without any

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relation whatsoever to the amount of power they generate). This payment based on investment (in €/MW of installed capacity) is supplemented, in the case of solar plants, by a return on operations payment (in €/MWh produced).

The principle driving 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 reasonable return is calculated as the average yield on Spanish government 10-year bonds on the secondary market in a 24-month period preceding the new regulatory period, plus a premium based on the financial condition of the Spanish electricity system and prevailing economic conditions.

This return can be revised every six years at the end of each regulatory period. The first regulatory period commenced on July 14, 2013, the date on which Royal Decree-Law 9/2013 became effective, and will end on December 31, 2019. The values of parameters used to calculate the payments can be changed at the end of each regulatory period, except for a plant’s useful life and the value of a plant’s initial investment. The Spanish government initiated its review of the rates of return on investment and return on operations with the publication of a draft of the law on December 28, 2018. This document includes several options for the plants affected by the Royal Decree-Law 9/2013, that would set the new reasonable return in between 7.09% and the existing 7.39%.

If the proposal is amended in the Spanish Parliament, and payments for renewable energy plants are revised to lower amounts in the next regulatory period starting on January 1, 2020 until December 31, 2025, this could have an adverse effect on our business, financial condition, results of operations and cash flows. As a reference, assuming our Spanish assets continue to perform as expected and assuming no additional changes of circumstances, with the information currently available we estimate that a reduction of 100 basis points in the reasonable rate of return on investment set by the Spanish government could cause a reduction in our cash available for distribution of approximately €12 million per year for the whole Spanish portfolio. This estimate is subject to certain assumptions, which may change in the future.

Additionally, the high electricity market prices experienced in recent years, which are also expected in 2019, are generating a future liability for our renewable plants in Spain, given the regulated price bands mechanism that reduces the risk of our plants from market prices fluctuations. Prices in Spain have been significantly above the regulated bands and any extra revenues received due to this situation will have to be returned through a reduction of the return on investment payment on future years. The current expected reduction in revenues due to this effect will be €7 million distributed through the life of all the assets of the Spanish portfolio.

There are other parameters, such as achieved market prices forecast, load factors and standard operational expenses, that could be updated on the regulatory review taking place in 2019, and that could therefore have a negative impact on the return on investment payment and the return on operations payment during the following years.

Revenues in our Portuguese wind farms are affected by regulation and government incentives.

Our wind farms in Portugal are operated under the remuneration scheme of Decree Law 339-C/2001, as well as the amendments to Decree Law 51/2010 and Decree Law 35/2013.

The remuneration scheme consists of a feed in tariff (expressed in €/MWh), which consists of a fixed component, variable component and an environmental component. Remuneration also depends on a “z” coefficient, which varies depending on the facility’s annual production. This remuneration is also updated according to monthly fluctuations in inflation.

The remuneration scheme of the wind farms is maintained for 15 years at a fixed price, which may be extended by an additional seven years with a variable price that has cap-and-floor system (Decree Law 35/2013).

The Portuguese government has approved charging the Energy Sector Extraordinary Contribution Tax (“CESE”) to renewable energy generators in 2019. The CESE has been in place since 2014. It was originally approved as an extraordinary tax that would remain in place for no longer than one year, and it only applied to non-renewable energy operators. Since then it has been extended every year. All of our wind farms in Portugal will be affected by the CESE tax for 2019, for an expected total negative impact of approximately €1 million.

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Revenue from our concessional assets 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 concession agreements in Uruguay, we have a long-term PPA with UTE, or Administracion Nacional de Usinas y Transmisiones Electricas, the Republic of 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. Governments may also postpone annual tariff increases until a new tariff structure is approved without compensating us for lost revenue. 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.

Renewable energy sources in Canada benefit from federal and provincial incentives, such as RPS programs, accelerated cost recovery deductions allowed for tax purposes, the availability of offtake agreements through RPS and the Ontario FIT program, and other commercially oriented incentives. Renewable energy sources in Chile benefit from an RPS program. Renewable energy sources also receive incentives from the governments of Spain and Portugal. Any adverse change to, or the elimination of, these incentives could have a material adverse effect on our business and our future growth prospects.

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 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;

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• 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 during the operating phase of these projects, 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.

Our international operations require us to comply with anti-corruption laws and regulations of the United States government and various non-U.S. jurisdictions.

Doing business in multiple countries requires us and our subsidiaries to comply with the laws and regulations of the United States government and various non-U.S. jurisdictions. Our failure to comply with these rules and regulations may expose us to liabilities. These laws and regulations may apply to us, our subsidiaries, individual directors, officers, employees and agents, and may restrict our operations, trade practices, investment decisions and partnering activities. In particular, our non-U.S. operations are subject to United States and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (“FCPA”). The FCPA prohibits United States companies and their officers, directors, employees and 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 FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, TerraForm Power 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. As a result, business dealings between our employees and any such foreign official could expose us to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between us and a private third party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures. We have established policies and procedures designed to assist us and our personnel in complying with applicable United States and non-U.S. laws and regulations; however, there is no assurance that these policies and procedures will completely eliminate the risk of a violation of these legal requirements, and any such violation (inadvertent or otherwise) could have a material adverse effect on our business, financial condition and results of operations.

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 and property damage. At

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least one of our concentrated solar power plants was found to have elevated levels of certain regulated thermal fluids, indicating the possibility of a leak of such fluids at the site. We are working with local regulators, as well as the site’s previous owner, to investigate the situation and determine the cause of the elevated levels of the thermal fluids. While there is no enforcement action against us at this time, there is no assurance that we will not face liability for this incident in the future.

In addition, certain environmental, health and safety laws may result in liability for failure to comply with periodic reporting and other administrative requirements and, 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 liabilities, 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. Wind power plants, in particular, involve a risk that protected species will be harmed, as the turbine blades travel at a high rate of 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 are known to strike and kill flying animals, and occasionally strike and kill endangered or protected species. As a result, we expect to observe industry guidelines and comply with regulator approved incidental take permits and governmentally recommended best practices to avoid harm to protected species, such as avoiding structures with perches, avoiding guy wires that may kill birds or bats in flight, or avoiding lighting that may attract protected species at night. In addition, we will attempt to reduce the attractiveness of a site to predatory birds through regular site maintenance (e.g., mowing, removal of animal and bird carcasses, etc.).

Where possible, we will 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. We are monitoring the U.S. Fish & Wildlife Service rulemaking and policy about obtaining incidental take permits for bald and golden eagles at locations with low to moderate risk of such events and will seek permits as appropriate, and continue to monitor rulemaking for other species. We are also in the process of amending the incidental take permits for one wind power plant in Hawaii, where, based on standardized monitoring, endangered species mortality has exceeded prior estimates and the permitted limit on such takings. We are cooperating with federal and state agencies to amend our incidental take permits to come into compliance.

Excessive taking of protected species could result in requirements to implement mitigation strategies, including modification of operations and/or substantial monetary fines and negative publicity. Our wind power plants in Hawaii, several of which hold incidental take permits to authorize the incidental taking of small numbers of protected species, are subject to curtailment (i.e., reduction in operations) if excessive taking of protected species is detected through monitoring. At some of the facilities in Hawaii, curtailment has been implemented, but not at levels that materially reduce electricity generation or revenues. Such curtailments (to protect bats) have reduced nighttime operation and limited operation to times when wind speeds are high enough to prevent bats from flying into a wind power plant’s blades. Additional curtailments are possible at those locations. We cannot guarantee that such curtailments, 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 related 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.

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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.

Any such terrorist acts, environmental repercussions or disruptions, natural disasters or theft incidents 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.

Any cyber-attack or other failure of the Company’s communications and technology infrastructure and systems could have a material adverse impact on the Company.

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 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, cyber attacks 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 cyber-attack 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.

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

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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 or other facility modifications.

The seasonality of our operations may affect our liquidity.

We will 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, the cash retained by us 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 quarterly results of operations may fluctuate significantly for various reasons, mostly related to economic incentives and weather patterns.

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 assets are located. Due to shorter daylight hours in 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 Activity

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;

• 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 dividends to the holders of our Class A 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 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 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 distribution, which may limit our ability to obtain

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additional financing, withstand downturns in our business and take advantage of business and development opportunities. If we breach our covenants, our corporate revolving credit facility, term loan facility 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 needed assets or take other actions that we might otherwise consider appropriate or desirable.

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 Class A common share.

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

• competing bids for a renewable energy facility, including from companies that may have substantially greater capital and other resources than we do;

• fewer third party acquisition opportunities than we expect, which could result from, among other things, available renewable energy facilities having less desirable economic returns or higher risk profiles than we believe suitable for our business plan and investment strategy;

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

• our access to 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 dividends per share, those acquisitions may in fact result in a decrease in dividends 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 acquisitions, 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 are based on assumptions and

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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, disrupt our ongoing business or not be successfully integrated. As a result, the consummation of acquisitions may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 to holders of our Class A common stock. 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 right of first offer 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. 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 permit. 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 dividends paid to holders of our Class A 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 cash available for distribution.

Even if we consummate acquisitions that we believe will be accretive to such cash per unit, those acquisitions may in fact result in a decrease in such cash per unit 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.

In the future, we may acquire certain assets in which we have limited control over management decisions and our interests in such assets may be subject to transfer or other related restrictions.

We own and may seek to acquire assets in which we own less than a majority of the related interests in the assets. In these investments, we will seek to exert a degree of influence with respect to the management and operation of assets in which we own less than a majority of the interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, we may not always succeed in such negotiations, and we may be dependent on our co-investors to operate such assets. Our co-investors may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally. In addition, conflicts of interest may arise in the future between us and our stockholders, on the one hand, and our co-investors, on the other hand, where our co-investors’ business interests are inconsistent with our interests and those of our stockholders. Further, disagreements or disputes between us and our co-investors could result in litigation, which could increase our expenses and potentially limit the time and effort our officers and directors are able to devote to our business.

The approval of co-investors also may be required for us to receive distributions of funds from assets or to sell, pledge, transfer, assign or otherwise convey our interest in such assets. Alternatively, our co-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. Co-investors may also seek to exercise consent rights that may inhibit our ability to manage the asset as we see fit. These restrictions may limit the price or interest level for our interests in such assets, in the event we want to sell such interests.

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

In the future, we intend to pay dividends 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

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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 their available cash to expand ongoing 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 the Company, 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.

• 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 dividends to holders of our Class A 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:

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

• any adverse consequences arising out of our separation from SunEdison and of the SunEdison Bankruptcy;

• 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;

• counterparties’ to our offtake agreements willingness and ability 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 and environmental laws;

• 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, 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;

• 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 dividends to holders of our Class A common stock. Furthermore, holders of our Class A 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 dividends to holders of our Class A common stock during the period. We are a holding company and 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 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 issued additional equity securities in connection with acquisition of our European Platform, and we may issue additional equity securities in connection with any other acquisitions or growth capital expenditures. The payment of dividends on these additional equity securities may increase the risk that we will be unable to maintain or increase our per share dividend. 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 Class A 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 Class A common stock.

Finally, dividends to holders of our Class A 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 dividends.

TerraForm Power’s payout ratio is a measure of its ability to make cash distributions to stockholders. TerraForm Power targets a long-term payout ratio of 80 to 85% of CAFD. From time to time, TerraForm Power’s payout ratio may exceed 100%, during periods of lower generation or lower merchant power prices or combination thereof. Because our business is

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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 dividends to stockholders in line with our stated targets.

Certain of our stockholders have accumulated large concentrations of holdings of our Class A shares, which among other things, may impact the liquidity of our Class A shares.

In addition to Brookfield, certain of our stockholders hold large positions in our Class A shares and new or existing stockholders may accumulate large positions in our Class A shares, which may impact the liquidity of shares of our Class A shares. In the event that stockholders hold these large positions in shares of our Class A common stock not owned by Brookfield this concentration of ownership may reduce the liquidity of our Class A 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 dividends 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 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 dividends, if any, declared by us. To the extent that we need funds to pay a quarterly cash dividend to holders of our Class A 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 dividends to holders of our Class A common stock.

Market interest rates may have an effect on the value of our Class A common stock.

One of the factors that influences the price of shares of our Class A common stock will be the effective dividend 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 Class A common stock to expect a higher dividend yield. If market interest rates increase and we are unable to increase our dividend 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 Class A common stock. As a result, the price of our Class A 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 Class A common stock.

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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 Class A common stock offered hereby. Under our amended and restated certificate of incorporation, we are authorized to issue 1,200,000,000 shares of Class A 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 Class A common stock or preferred stock or convertible debt may create downward pressure on the trading price of our Class A common stock. We may also issue additional shares of our Class A common stock or other securities that are convertible into or exercisable for our Class A 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 Class A 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 Class A common stock adversely, the stock price and trading volume of our Class A common stock could decline.

The trading market for our Class A 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 Class A common stock adversely, or provide more favorable relative recommendations about our competitors, the price of our Class A 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 Class A common stock to decline.

The settlement of certain existing litigation will trigger a requirement to issue additional Class A common stock to Brookfield.

We have agreed pursuant to the merger and sponsorship transaction agreement (the “Merger Agreement”) dated March 6, 2017 among the Company, Orion Holdings and BRE TERP Holdings Inc., to issue additional shares of Class A common stock to Brookfield for no additional consideration in respect of the final resolution of certain specified litigation (see Note 18. Commitments and Contingencies to our consolidated financial statements for a description of such litigation). The number of additional shares of Class A 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. The number of shares of Class A common stock to be issued to Brookfield could 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, 2018, 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 on Form 10-K. These control deficiencies create a reasonable possibility that a material misstatement to the consolidated financial

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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, 2018.

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, 2018, the net carrying value of long-lived assets represented $8,587.0 million, or 92%, 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.

We currently have a REC sales agreement with a customer expiring December 31, 2021 that is significant to a distributed generation solar project, 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 would likely result in a significant decrease in our expected revenues. Our 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. We 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 our consolidated statements of operations for the year endedDecember 31, 2018. There has been no impairment of intangible assets to date. If intangible assets or additional renewable energy facilities are impaired based on a future impairment test, we could be required to record further non-cash impairment charges to our operating income. Such non-cash impairment charges, if significant, could materially and adversely affect our results of operations in the period recognized.

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 exceeds its carrying value. As of December 1, 2018, we performed a qualitative impairment test for the goodwill balance in Saeta of $120.6 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, 2018.

Risks Related to our Relationship with Brookfield

We may not realize the expected benefits of Brookfield sponsorship.

Following the transition to Brookfield sponsorship, we may not perform as we expect, or as the market expects, which could have an adverse effect on the price of our Class A common stock. The Company 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 be able to 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 Class A common stock and on our business, growth and the results of our operations.

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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.

Brookfield owns an approximate 65% interest in the Company. 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 Class A 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 Class A 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, primarily hydroelectric facilities and wind 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 Class A 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 65% interest in the Company, the ability of other holders of our Class A common stock to exercise control over the corporate governance of the Company will be limited. In addition, due to its approximate 65% interest in the Company, Brookfield has a substantial influence on our affairs and its voting power 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 Class A common stock.” above, Brookfield may hold certain interests that are different from ours or other holders of our Class A 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 Class A common stock.

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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 Class A 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 Global Select Market 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.

Other Risks

We may face difficulty in transitioning important corporate, project and other services to new vendors, which involves management challenges and poses risks that may materially adversely affect our business, results of operations and financial condition.

Beginning in 2017, as we transitioned away from our historical dependence on SunEdison for corporate, project and other services, including providing for critical systems and information technology infrastructure sponsorship, we engaged new vendors and/or developed our own capabilities and resources for corporate, project and other services, including providing for critical systems and information technology infrastructure. These efforts included creating a separate stand-alone corporate organization, including, among other things, directly hiring employees and establishing our own accounting, information

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technology, human resources and other systems and infrastructure, and also include transitioning the project-level O&M and asset management services in-house or to third party service providers. While these efforts are largely complete, they involve a number of new risks and challenges that may materially adversely affect our business, results of operations and financial condition.

Finalizing these changes may take longer than we expect, cost more than we expect, and divert management’s attention from other aspects of our business. We may also incur substantial legal and compliance costs in many of the jurisdictions where we operate.

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.

We did not file with the SEC on a timely basis our Annual Reports on Form 10-K for each of the years ended December 31, 2015 and 2016 and our Quarterly Reports on Form 10-Q for each of the quarters ended March 31, 2016, June 30, 2016, September 30, 2016, March 31, 2017, June 30, 2017 and March 31, 2018. We filed our Annual Reports on Form 10-K for the year ended December 31, 2017 and 2018, and our Quarterly Reports on Form 10-Q for each of the quarters ended September 30, 2017 and June 30, 2018 after the applicable filing deadline but within the applicable grace period provided by 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 Class A common stock would likely be delisted from the Nasdaq Global Select Market.

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, as a result of the delayed filing of our periodic reports with the SEC, we will not be eligible to register the offer and sale of our securities using a short-form registration statement on Form S-3 until we have timely filed all periodic reports required under the Exchange Act for one year. 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 dividends.

Financial statements at the project-level have also been delayed over the course of 2016, 2017 and 2018. This delay created defaults under most 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

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.

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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. Further, the 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. Further, 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 dividends.

If we makes 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 dividend 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 its 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 its 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 solar facilities and utility-scale power plants that are located in the United States (including Puerto Rico), Canada, the United Kingdom, Spain, Portugal, Uruguay and Chile with a combined nameplate capacity of 3,738 MW as of December 31, 2018. We have financed certain of our assets through project specific debt secured by the renewable energy facility's assets (mainly the renewable energy facility) 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 solar facilities

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 some 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 within our distributed generation solar 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

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addition, 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 the renewable energy facilities.

Concentrated solar power

Concentrated solar power plants use mirrors to concentrate the energy from the sun to generate heat which will be either temporarily stored or used to drive traditional steam turbines or engines that create electricity. Our concentrated solar projects consist of parabolic troughs that concentrate reflected light onto a receiver tube. The tube is filled with a working fluid, typically molten salt, which is then heated by the concentrated sunlight and used to heat water for a standard steam power generation system. The energy produced by the CSP facilities is produced in AC.

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 solar photovoltaic or 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.

Item 3. Legal Proceedings.

See Note 18. Commitments and Contingenciesto our consolidated financial statements included in this Annual Report on Form 10-K 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.

Class A Common Stock

TerraForm Power's Class A common stock began trading on the Nasdaq Global Select Market under the symbol “TERP” on July 18, 2014. Prior to that, there was no public market for our Class A 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 Class A 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, 2019, there were 13 holders of record of TerraForm Power’s Class A common stock and the closing sale price per share of our Class A common stock on the Nasdaq Global Select Market was $12.51. Affiliates of Brookfield held approximately 65% of TerraForm Power's Class A common stock as of that date.

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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 Class A common stock from July 18, 2014 through December 31, 2018, 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 was invested on the initial public offering date in each of the Class A common stock of the Company, the stocks in the S&P 500, the Nasdaq Composite Index, our peer group, and that all dividends were reinvested.

Comparison of Cumulative Total Return

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.

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Item 6. Selected Financial Data.

Our historical selected financial data is presented in the following table. For all periods prior to our initial public offering (“IPO”) on July 23, 2014, the amounts shown in the table below represent the combination of TerraForm Power and Terra LLC, the accounting predecessor, and were prepared using SunEdison's historical basis in assets and liabilities. For all periods subsequent to the IPO, 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.

	Year Ended December 31,
(In thousands, except per share data)	2018			2017			2016			2015			2014
Statements of Operations Data:
Operating revenues, net	$	766,570		$	610,471		$	654,556		$	469,506		$	127,156
Operating costs and expenses:
Cost of operations	220,907			150,733			113,302			70,468			10,630
Cost of operations - affiliate	—			17,601			26,683			19,915			8,063
General and administrative expenses	87,722			139,874			89,995			55,811			20,984
General and administrative expenses - affiliate	16,239			13,391			14,666			55,330			19,144
Acquisition costs	7,721			—			2,743			49,932			10,177
Acquisition costs - affiliate	6,925			—			—			5,846			5,049
Loss on prepaid warranty - affiliate	—			—			—			45,380			—
Impairment of goodwill	—			—			55,874			—			—
Impairment of renewable energy facilities	15,240			1,429			18,951			—			—
Depreciation, accretion and amortization expense	341,837			246,720			243,365			161,310			41,280
Formation and offering related fees and expenses	—			—			—			—			3,570
Formation and offering related fees and expenses - affiliate	—			—			—			—			1,870
Total operating costs and expenses	696,591			569,748			565,579			463,992			120,767
Operating income	69,979			40,723			88,977			5,514			6,389
Other expenses (income):
Interest expense, net	249,211			262,003			310,336			167,805			86,191
Loss on extinguishment of debt, net	1,480			81,099			1,079			16,156			(7,635		)
Gain on sale of renewable energy facilities	—			(37,116		)	—			—			—
(Gain) loss on foreign currency exchange, net	(10,993		)	(6,061		)	13,021			19,488			14,007
Loss on investments and receivables - affiliate	—			1,759			3,336			16,079			—
Other (income) expenses, net	(4,102		)	(5,017		)	2,218			7,362			438
Total other expenses, net	235,596			296,667			329,990			226,890			93,001
Loss before income tax (benefit) expense	(165,617		)	(255,944		)	(241,013		)	(221,376		)	(86,612		)
Income tax (benefit) expense	(12,290		)	(19,641		)	2,734			(12,584		)	(4,689		)
Net loss	$	(153,327	)	$	(236,303	)	$	(243,747	)	$	(208,792	)	$	(81,923	)
Net income (loss) attributable to Class A common stockholders	$	12,380		$	(160,154	)	$	(123,511	)	$	(78,832	)	$	(25,617	)
Basic and diluted loss per Class A common share	0.07			(1.61		)	(1.40		)	(1.24		)	(0.87		)
Dividends declared per Class A common share	0.76			1.94			—			1.01			0.44

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	As of December 31,
(In thousands)	2018		2017		2016		2015		2014
Balance Sheet Data:
Cash and cash equivalents	$	248,524	$	128,087	$	565,333	$	626,595	$	468,554
Restricted cash	144,285		96,700		117,504		159,904		81,000
Renewable energy facilities, net	6,470,026		4,801,925		4,993,251		5,834,234		2,648,212
Long-term debt and financing lease obligations1	5,761,845		3,598,800		3,950,914		4,562,649		1,699,765
Total assets	9,330,354		6,387,021		7,705,865		8,217,409		3,680,423
Total liabilities	6,561,937		3,964,649		4,810,396		5,101,429		2,140,164
Redeemable non-controlling interests	33,495		34,660		165,975		175,711		24,338
Total stockholders’ equity	2,734,922		2,387,712		2,729,494		2,940,269		1,515,921

———

(1) Including the current portion.

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 a 3,738 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 $350 billion in assets under management. Affiliates of Brookfield held approximately 65% of TerraForm Power’s Class A common stock as of December 31, 2018.

Our goal is to pay dividends 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 purposes. We expect to generate this return with a regular dividend, 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:

We focus on sourcing off-market transactions at more attractive valuations than auction processes. Our successful acquisition of Saeta provides us with a European Platform and is an example of these opportunities. 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 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.

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• Margin Enhancements:

We believe there is significant opportunity to enhance our cash flow through optimizing the performance of our existing assets. As our recently announced long-term service agreements (collectively, the “LTSA”) with an affiliate of General Electric 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. We are currently seeking to execute similar agreements to optimize the performance of our North American solar and European wind fleets.

• 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 power, property, infrastructure and private equity. Brookfield has approximately $47 billion in renewable power assets under management, representing approximately 17,400 MW of generation capacity in 15 countries. It also employs over 2,500 individuals with extensive operating, development and power marketing capabilities and has a demonstrated ability to deploy capital in a disciplined manner, having developed or acquired 13,200 MW of renewable generation capacity since 2012.

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, 2018, 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 as we produce electricity. RECs are accounted for as governmental incentives and are not considered output of the underlying renewable energy facilities. These RECs are currently sold pursuant to agreements with third parties and a certain debt holder, and REC revenue under bundled arrangements is recognized as the underlying electricity is generated if the sale has been contracted with the customer. Under the terms of certain debt agreements with a creditor, SRECs are transferred directly to the creditor to reduce principal and interest payments due under solar program 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 Wind and Solar segment, revenue is regulated by the Spanish government. In Spain, renewable electricity producers receive the merchant price for the power they produce and 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 reasonable return is calculated as the average yield on Spanish government 10-year bonds on the secondary

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market in a 24-month period preceding the new regulatory period, plus a premium based on the financial condition of the Spanish electricity system and prevailing economic conditions. The amount of the return is recalculated at the end of each six-year regulatory period. The first regulatory period began on July 14, 2013, and will end on December 31, 2019. The next regulatory period will begin on January 1, 2020.

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 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 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 dividend. We intend to mitigate the effects of any seasonality that we experience by reserving a portion of our cash available for distribution and otherwise maintain sufficient liquidity, including cash on hand in order to, among other things, facilitate the payment of dividends 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 company. 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. Over the course of 2016 and 2017, our ability to distribute funds from our renewable energy facilities was limited for substantially all of its renewable energy facilities with non-recourse financing due to project-level defaults related to the SunEdison Bankruptcy and the failure to timely deliver audited financial statements. 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 dividends to the holders of our Class A 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.

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Renewable energy facility acquisitions and investments

Our long-term growth strategy is dependent on our ability to acquire additional renewable power generation assets. This growth is expected to be comprised 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.

Access to capital markets

Our ability to acquire additional clean power generation assets and manage our other commitments may be dependent on our ability to raise or borrow additional funds and access debt and equity capital markets, including the equity capital markets for our Class A shares, the corporate debt markets and the project finance market for project-level debt. We accessed the capital markets several times in 2018, including in connection with our Revolver, Term Loan and Equity Infusion (as defined and discussed in Financing Activities within 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. Currently, a significant portion of our revenues and expenses are generated in U.S. Dollars. Historically, we have also had significant revenue and expenses generated in other currencies, including the Euro, the Canadian dollar and, to a lesser extent, the British Pound. This mix of currencies changed over the course of 2018 as a result of the closing of the acquisition of Saeta on June 12, 2018. This mix 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 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

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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

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 3,738 MW and 2,698 MW as of December 31, 2018 and 2017, 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 endedDecember 31, 2018, 2017 and 2016 were as follows:

Operating Metrics	Year Ended December 31,
(In GWh)	2018	2017	2016
Solar segment	1,819	1,895	2,225
Wind segment	5,457	5,381	5,499
Regulated Solar and Wind segment1	812	—	—
Total	8,088	7,276	7,724

———

(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

The amounts shown in the table below represent the results of TerraForm Power, which consolidates Terra LLC through its controlling interest. The following table illustrates the consolidated results of operations for the years endedDecember 31, 2018, 2017 and 2016:

	Year Ended December 31,
(In thousands)	2018			2017			2016
Operating revenues, net	$	766,570		$	610,471		$	654,556
Operating costs and expenses:
Cost of operations	220,907			150,733			113,302
Cost of operations - affiliate	—			17,601			26,683
General and administrative expenses	87,722			139,874			89,995
General and administrative expenses - affiliate	16,239			13,391			14,666
Acquisition costs	7,721			—			2,743
Acquisition costs - affiliate	6,925			—			—
Impairment of goodwill	—			—			55,874
Impairment of renewable energy facilities	15,240			1,429			18,951
Depreciation, accretion and amortization expense	341,837			246,720			243,365
Total operating costs and expenses	696,591			569,748			565,579
Operating income	69,979			40,723			88,977
Other expenses (income):
Interest expense, net	249,211			262,003			310,336
Loss on extinguishment of debt, net	1,480			81,099			1,079
Gain on sale of renewable energy facilities	—			(37,116		)	—
(Gain) loss on foreign currency exchange, net	(10,993		)	(6,061		)	13,021
Loss on investments and receivables - affiliate	—			1,759			3,336
Other (income) expenses, net	(4,102		)	(5,017		)	2,218
Total other expenses, net	235,596			296,667			329,990
Loss before income tax (benefit) expense	(165,617		)	(255,944		)	(241,013		)
Income tax (benefit) expense	(12,290		)	(19,641		)	2,734
Net loss	(153,327		)	(236,303		)	(243,747		)
Less: Net income attributable to redeemable non-controlling interests	9,209			1,596			6,482
Less: Net loss attributable to non-controlling interests	(174,916		)	(77,745		)	(126,718		)
Net income (loss) attributable to Class A common stockholders	$	12,380		$	(160,154	)	$	(123,511	)

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Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Operating Revenues, net

Operating revenues, net for the years ended December 31, 2018 and 2017 were as follows:

	Year Ended December 31,
(In thousands, other than MW data)	2018		2017		Change
Energy:
Solar	$	228,433	$	232,791	$	(4,358	)
Wind	264,585		246,838		17,747
Regulated Solar and Wind	166,984		—		166,984
Incentives including affiliates:
Solar	70,533		104,442		(33,909		)
Wind	16,364		26,400		(10,036		)
Regulated Solar and Wind	19,671		—		19,671
Total operating revenues, net	$	766,570	$	610,471	$	156,099
GWh sold:
Solar	1,819		1,895		(76		)
Wind	5,457		5,381		76
Regulated Solar and Wind	812		—		812
Total GWh sold	8,088		7,276		812
	December 31,
Nameplate capacity (MW):	2018		2017		Change
Solar	1,092		1,084		8
Wind	1,854		1,614		240
Regulated Solar and Wind	792		—		792
Total nameplate capacity	3,738		2,698		1,040

Our European Platform, consisting of the assets in Saeta, was acquired in June 2018 and contributed energy revenue of $167.0 million to the new Regulated Solar and Wind segment, which represented its entire operations in Spain. Energy revenue for our Solar segment decreased by $4.4 million during the year ended December 31, 2018, compared to 2017, primarily due to a $7.1 million decrease resulting from the sale of renewable energy facilities in the second quarter of 2017 that was partially offset by a $2.7 million increase in solar availability in 2018. Energy revenue for our Wind segment increased by $17.7 million during the year ended December 31, 2018, compared to 2017, primarily driven by a $34.6 million contribution from Saeta’s operations in Portugal and Uruguay and a $2.3 million increase in unrealized gains on commodity derivative contracts not designated as hedging instruments. These increases in revenue were partially offset by (i) a $10.1 million decrease due to lower availability; (ii) a $7.6 million reduction due to lower basis pricing in Texas as a result of continued challenged market conditions; (iii) a $4.5 million decrease driven by lower resource in Central Wind; and (iv) a $3.2 million decrease due to the change in revenue recognition policy (see Note 2. Summary of Significant Accounting Policies and Note 3. Revenue to our consolidated financial statements). The outages at Raleigh and Bishop Hill were primarily caused by the failure of a single faulty blade which caused the collapse of a tower at our Raleigh wind facility. While we worked to determine the root cause of the blade failure, we removed from service all 70 turbines at Raleigh and Bishop Hill that utilized the same blades. After a thorough investigation and rigorous inspections of the blades, all turbines were returned to service between mid-March and the end of April 2018.

Incentive revenue for our Solar segment decreased by $33.9 million during the year ended December 31, 2018, compared to 2017, primarily due to: (i) a $13.6 million decrease in REC revenue due to the change in revenue recognition accounting policy; (ii) a $7.6 million reduction resulting from the sale of renewable energy facilities in the second quarter of

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2017; (iii) a $6.4 million decrease in deferred revenue related to the upfront sale of investment tax credits, as a result of the adoption of the new revenue recognition standard in 2018; and (iv) a $2.5 million reduction due to decreased REC sales to one off-taker that declared bankruptcy during the first quarter of 2018 (see Note 5. Renewable Energy Facilities to our consolidated financial statements). Incentive revenue for our Wind segment decreased by $10.0 million, primarily due to the change in revenue recognition timing for RECs resulting from the adoption of the new revenue standard in 2018. Our European Platform contributed Incentive revenue of $19.7 million in the Regulated Solar and Wind segment from the date of acquisition.

Cost of Operations

Cost of operations for the years ended December 31, 2018 and 2017 was as follows:

	Year Ended December 31,
(In thousands)	2018		2017		Change
Cost of operations:
Solar	$	64,343	$	54,766	$	9,577
Wind	116,017		95,967		20,050
Regulated Solar and Wind	40,547		—		40,547
Cost of operations - affiliate:
Solar	—		10,542		(10,542		)
Wind	—		7,059		(7,059		)
Total cost of operations	$	220,907	$	168,334	$	52,573

Historically, O&M as well as asset management services were provided to us substantially by SunEdison pursuant to contractual agreements. We completed the transitioning away from SunEdison during 2017 and accordingly did not incur any cost of operations related to an affiliate in 2018; such cost amounted to $10.5 million and $7.1 million for our Solar and Wind segments for the year ended December 31, 2017, respectively.

Total cost of operations for our Solar segment decreased by $1.0 million for the year ended December 31, 2018 compared to 2017 primarily due to (i) the sale of our portfolio of solar power plants located in the United Kingdom (24 operating projects representing an aggregate 365.0 MW) in May of 2017 (the “U.K. Portfolio”) and our residential rooftop solar assets portfolio (11.4 MW of assets) in the United States that had a total cost of operations of $3.4 million for the year ended December 31, 2017; and (ii) a decrease of $2.9 million in interconnection costs. The decrease in the cost of operations in our Solar segment was partially offset by a $4.5 million loss on a note receivable from a public utility company that filed for protection under Chapter 11 of the U.S. bankruptcy code in January of 2019. Total cost of operations for our Wind segment increased by $13.0 million primarily due to (i) $4.8 million of costs related to Saeta’s projects in Portugal and Uruguay that were acquired during the second half of 2018; (ii) a $2.3 million increase in the cost of spare parts used due to in-sourcing of certain project-level services that were previously provided by SunEdison; and (iii) a $5.6 million increase in the cost of repairs of the wind fleet required prior to the commencement of long-term service agreements with an affiliate of General Electric.

General and Administrative Expenses

General and administrative expenses for the years ended December 31, 2018 and 2017 were as follows:

	Year Ended December 31,
(In thousands)	2018		2017		Change
General and administrative expenses:
Solar	$	10,435	$	2,973	$	7,462
Wind	7,186		2,276		4,910
Regulated Solar and Wind	5,742		—		5,742
Corporate	64,359		134,625		(70,266		)
Total general and administrative expenses	$	87,722	$	139,874	$	(52,152	)
General and administrative expenses - affiliate:
Corporate	$	16,239	$	13,391	$	2,848

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General and administrative expenses decreased by $52.2 million during the year ended December 31, 2018, compared to 2017, driven by a $70.3 million decrease in corporate general and administrative expenses. The decrease in corporate general and administrative expenses is primarily due to: (i) the one-off payment in 2017 relating to the success-based advisory fee of $27.0 million paid upon the consummation of the Merger; (ii) a $27.7 million decrease in employee compensation costs driven by $16.5 million in lower stock-based compensation and $11.2 million in salaries and bonuses; and (iii) lower professional fees of $18.8 million, primarily reflecting (a) a $6.8 million decrease in legal services as a result of litigation and transaction costs incurred in connection with the Merger and (b) a $12.0 million decrease in accounting and other advisory services incurred related to AlixPartners LLP fees due to former interim Chief Accounting Officer and Chief Operating Officer support in 2017. The decrease in corporate general and administrative expenses was partially offset by an increase of $5.0 million in technology costs as a result of the implementation of information technology and other critical systems infrastructure.

The increase in the general and administrative expenses of $7.5 million and $4.9 million in our Solar and Wind segments, respectively, were primarily due to higher professional fees. The new Regulated Solar and Wind segment contributed $5.7 million to the total general administrative expenses.

General and administrative expenses - affiliate were $16.2 million for the year ended December 31, 2018, which consisted of a $14.6 million base management fee pursuant to the Brookfield MSA and $1.6 million of rent and other related expenses associated with the transition to our new corporate headquarters in New York. General and administrative expenses - affiliate were $13.4 million for the year ended December 31, 2017, which consisted of (i) a $3.4 million base management fee to Brookfield; (ii) a $4.5 million management fee paid to SunEdison prior to the Merger; and (iii) $5.4 million of stock-based expense related to SunEdison.

Impairment of Renewable Energy Facilities

On March 31, 2018, one customer with whom we had a REC sales agreement expiring on December 31, 2021 that was significant to an operating project within the Enfinity solar distributed generation portfolio, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. The potential replacement of the contract resulted in a significant decrease in expected revenues for this operating project. Our 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 the undiscounted cash flow forecast. Accordingly, we 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 within impairment of renewable energy facilities in our consolidated statements of operations for the year ended December 31, 2018 equal to the difference between the carrying amount and the estimated fair value.

We sold our remaining 0.3 MW of residential assets during the third quarter of 2017. Prior to the 2017 sale, we 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 our consolidated statements of operations for the year ended December 31, 2017.

Acquisition Costs

As discussed in Note 4. Acquisitionsand Dispositions to our consolidated financial statements, on June 12, 2018, we completed the acquisition of the Tendered Shares (as defined in Note 4. Acquisitions and Dispositions) of Saeta for total aggregate consideration of $1.12 billion and assumed $1.91 billion of project-level debt. With greater than 90% of the shares of Saeta acquired, we pursued a statutory squeeze out procedure under Spanish law to procure the remaining approximately 5% of the shares of Saeta, which closed on July 2, 2018 for a consideration of $54.6 million.

Acquisition costs were $14.6 million for the year ended December 31, 2018, and consisted, primarily of investment banker advisory fees 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 (see Note 19. Related Parties to our consolidated financial statements). These costs are reflected as acquisition costs and acquisition costs - affiliate (see Note 19. Related Parties to our consolidated financial statements). There were no acquisition costs incurred by us for the year ended December 31, 2017.

Depreciation, Accretion and Amortization Expense

Depreciation, accretion and amortization expense increased by $95.1 million during the year ended December 31, 2018, compared to 2017, primarily as a result of incremental depreciation, accretion and amortization associated with acquired renewable energy assets from Saeta and capital additions placed in service in 2018.

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Interest Expense, Net

	Year Ended December 31,
(In thousands)	2018		2017		Change
Corporate-level	$	119,418	$	114,166	$	5,252
Non-recourse:
Solar	63,571		70,439		(6,868		)
Wind	50,712		77,398		(26,686		)
Regulated Solar and Wind	15,510		—		15,510
Total interest expense, net	$	249,211	$	262,003	$	(12,792	)

Interest expense, net decreased by $12.8 million during the year ended December 31, 2018, compared to 2017, primarily driven by the decrease at our Solar and Wind segments. The decrease of $6.9 million at our Solar segment was primarily due to (i) the sale of the U.K. Portfolio, which had interest expense of $8.5 million for the year ended December 31, 2017; and (ii) $2.1 million due to the reduction of outstanding balance from regular repayments. Such decrease was partially offset by $3.3 million interest expense on new project finance debt obtained during 2018. The decrease of $26.7 million in interest expense at our Wind segment was primarily due to: (i) a $29.7 million decrease due to the repayment of the remaining outstanding principal balance of a $300.0 million Midco Portfolio Term Loan (as defined as defined in Note 10. Long-Term Debt to our consolidated financial statements) in the fourth quarter of 2017; and (ii) a $4.2 million decrease due to the reduction of the outstanding debt balances. The decrease at our Wind segment was partially offset by $8.0 million of expense in 2018 related to Saeta’s project-level debt in Portugal and Uruguay since the date of acquisition. The $5.3 million increase in net corporate interest expense was primarily related to increased borrowings under the Revolver (as defined as defined in Note 10. Long-Term Debt to our consolidated financial statements), the proceeds of which were used to fund the acquisition of Saeta. The new Regulated Solar and Wind segment had net interest expense of $15.5 million for the year ended December 31, 2018.

Loss on Extinguishment of Debt, net

We incurred a net loss on extinguishment of debt of $1.5 million for the year ended December 31, 2018, compared to a loss of $81.1 million in the prior year. The loss for the year ended December 31, 2018 represents the deferred financing costs written off and other charges related to the repricing of our Term Loan that took place in May of 2018. The loss for the year ended December 31, 2017 comprised of (i) a $72.3 million loss on the extinguishment of our Old Senior Notes due 2023, including the $50.7 million make-whole premium and the write-off of $21.6 million of unamortized deferred financing costs and debt discounts as of the redemption date; (ii) a $4.5 million loss as a result of the termination of the Old Revolver representing write-off of unamortized deferred financing fees as of the redemption date; and (iii) a $4.3 million loss due to other reductions in borrowing capacity for the Old Revolver during the year ended December 31, 2017 prior to its termination and prepayments and a final repayment of a non-recourse portfolio term loan prior to the date a change of control would have occurred. See Note 10. Long-term Debt to our consolidated financial statements for more details.

Gain on Sale of Renewable Energy Facilities

On May 11, 2017, we announced that Terra Operating LLC completed its previously announced sale of its U.K. Portfolio to Vortex Solar UK Limited, a renewable energy platform managed by the private equity arm of EFG Hermes, an investment bank. We recognized a gain on the sale of $37.1 million within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

(Gain) Loss on Foreign Currency Exchange, net

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 are primarily denominated in Euro. We recognized a net gain on foreign currency exchange of $6.1 million for the year ended December 31, 2017 due to a $7.1 million unrealized gain on the remeasurement of intercompany loans (which were primarily denominated in Canadian dollars as of the end of 2017), offset by $1.0 million of realized and unrealized net losses on foreign currency derivatives.

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Loss on Investments and Receivables - Affiliate

We incurred a net loss on investments and receivables - affiliate of $1.8 million during the year ended December 31, 2017, due to the write-off of receivables from SunEdison upon the consummation of the Merger and the effectiveness of the settlement agreement with SunEdison (the “Settlement Agreement”) on October 16, 2017. No other losses were recorded during the year ended December 31, 2018.

Other (Income) Expenses, net

We recognized $4.1 million of other income, net for the year ended December 31, 2018 compared to $5.0 million for the year ended December 31, 2017. The balance is primarily comprised on reimbursements and recoveries received for damages and other losses.

Income Tax Expense (Benefit)

Net income tax benefit from continuing operations for the year ended December 31, 2018 was $12.3 million, compared to $19.6 million for the year ended December 31, 2017. A valuation allowance is recorded against certain deferred tax assets in the U.S., Chile and certain other jurisdictions, primarily because of the history of losses in those jurisdictions. The tax benefit recognized in 2018 was comprised of a $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. and the recognition of deferred tax expense on the Company’s profits in certain jurisdictions, primarily in Spain. For the years ended December 31, 2018 and 2017, the overall effective tax rates of 7.4% and 9.0% were different than the statutory rates in the United States of 21% and 35%, respectively, 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.

Net Loss Attributable to Non-Controlling Interests

Net loss attributable to non-controlling interests, including redeemable non-controlling interests, was $165.7 million for the year ended December 31, 2018, compared to $76.1 million in the prior year. The increase in the loss is primarily due to the reduction in the tax rate used in the Hypothetical Liquidation at Book Value (“HLBV”) methodology applied by us and described in Note2. Summary of Significant Accounting Policies. In the calculation of the carrying values through HLBV, we 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. See Note 17. Non-Controlling Interests for more details.

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Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Operating Revenues, net

Operating revenues, net for the years ended December 31, 2017 and 2016 were as follows:

	Year Ended December 31,
(In thousands, other than MW data)	2017		2016		Change
Energy:
Solar	$	232,791	$	258,114	$	(25,323	)
Wind	246,838		248,617		(1,779		)
Incentives including affiliates:
Solar	104,442		119,374		(14,932		)
Wind	26,400		28,451		(2,051		)
Total operating revenues, net	$	610,471	$	654,556	$	(44,085	)
GWh sold:
Solar	1,895		2,225		(330		)
Wind	5,381		5,499		(118		)
Total GWh sold	7,276		7,724		(448		)
	December 31,
Nameplate capacity (MW):	2017		2016		Change
Solar	1,084		1,452		(368		)
Wind	1,614		1,531		83
Total nameplate capacity	2,698		2,983		(285		)

Energy revenue for our Solar segment decreased by $25.3 million during the year ended December 31, 2017, compared to the same period in 2016, primarily due to a $16.1 million decrease resulting from the sale of renewable energy facilities in the second quarter of 2017, a $5.7 million decrease due to lower Distributed Generation solar resource and a $7.7 million decrease due to lower Utility solar resource. Energy revenue for our Wind segment decreased by $1.8 million driven by a $13.6 million decrease resulting from lower Utility wind resource that was partially offset by a $6.7 million increase due to higher availability of our fleet and a $4.9 million increase in unrealized gains on commodity contract derivatives.

Incentive revenue for our Solar segment decreased by $14.9 million during the year ended December 31, 2017, compared to the same period in 2016, primarily due to a $19.6 million decrease resulting from the sale of renewable energy facilities in the second quarter of 2017 that was partially offset by a $9.1 million increase resulting from higher contracting of incentives as compared to the prior year. Incentive revenue for our Wind segment decreased by $2.1 million, primarily due to lower contracting of incentives as compared to the prior year.

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Costs of Operations

Costs of operations for the years ended December 31, 2017 and 2016 were as follows:

	Year Ended December 31,
(In thousands)	2017		2016		Change
Cost of operations:
Solar	$	54,766	$	27,934	$	26,832
Wind	95,967		85,368		10,599
Cost of operations - affiliate:
Solar	10,542		22,851		(12,309		)
Wind	7,059		3,832		3,227
Total cost of operations	$	168,334	$	139,985	$	28,349

Cost of operations for our Solar and Wind segments increased by $26.8 million and $10.6 million, respectively, during the year ended December 31, 2017, compared to the same period in 2016, primarily resulting from transitioning away from SunEdison for O&M and asset management services. Costs for asset management and O&M services provided by SunEdison are reported as cost of operations - affiliate, which decreased by $12.3 million for our Solar segment and increased by $3.2 million for our Wind segment, compared to the same period in the prior year. The increase in affiliate costs for our Wind segment was driven by higher inventory and repairs and maintenance costs. Total cost of operations, including cost of operations - affiliate, increased $28.3 million, and was driven by a $5.8 million loss on disposals of property and equipment resulting from the replacement of major components at certain of our wind power plants, higher costs for asset management and O&M services provided by unaffiliated third parties and higher costs for project-level accounting services. During 2016, SunEdison provided project-level accounting services to us pursuant to asset management agreements and the costs were recognized as cost of operations - affiliate. Due to the transition away from SunEdison, project accounting was brought in-house during 2017, and we incurred significantly higher costs for these services due to our reliance on an hourly-based contractor workforce combined with the increased level of effort involved with filing our past due annual and quarterly reports and regaining compliance with Nasdaq listing requirements.

General and Administrative Expenses

General and administrative expenses for the years ended December 31, 2017 and 2016 were as follows:

	Year Ended December 31,
(In thousands)	2017		2016		Change
General and administrative expenses:
Solar	$	2,973	$	15,353	$	(12,380	)
Wind	2,276		2,387		(111		)
Corporate	134,625		72,255		62,370
Total general and administrative expenses	$	139,874	$	89,995	$	49,879
General and administrative expenses - affiliate:
Corporate	$	13,391	$	14,666	$	(1,275	)

General and administrative expenses increased by $49.9 million during the year ended December 31, 2017, compared to the same period in 2016, driven by a $62.4 million increase in corporate general and administrative expenses. The increase in corporate general and administrative expenses is primarily due to the incurrence of $27.0 million of success based advisory fees paid upon the consummation of the Merger, a $24.8 million increase in employee compensation costs, and an increase in professional fees for legal, accounting and advisory services resulting from transition to standalone operations and the Merger. The increase in employee compensation was driven by a $9.3 million increase in annual incentive and retention bonuses to retain key employees, a $7.9 million increase in stock-based compensation expense due to the vesting of all previously unvested restricted stock units (“RSUs”) triggered by the change in control upon the consummation of the Merger, a $3.7 million increase for severance and transition bonus costs incurred as a result of our restructuring plan subsequent to the Merger and a $3.2 million increase in salaries and benefits costs due to directly hiring and retaining former employees of SunEdison.

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General and administrative expenses - affiliate decreased by $1.3 million during the year ended December 31, 2017, compared to the same period in 2016, due to a $7.5 million decrease in the management and administrative services provided by SunEdison subsequent to the SunEdison Bankruptcy, partially offset by a $3.4 million base management fee charge recorded in the fourth quarter pursuant to the Brookfield MSA and a $2.8 million increase in stock-based compensation expense that was allocated to us for unvested equity awards held by our employees in the stock of SunEdison, Inc. This increase was largely driven by the recognition of all previously unrecognized compensation cost pertaining to these awards as a result of the bankruptcy court's approval of SunEdison's plan of reorganization in July of 2017, which provided that all unvested equity awards in the stock of SunEdison, Inc. would be canceled.

Goodwill Impairment

We performed our annual impairment test of the carrying value of our goodwill as of December 1, 2016 and concluded that the goodwill balance of $55.9 million was fully impaired. The impairment was driven by a combination of factors, including lack of near-term growth in the operating segment. The impairment test determined there was no implied value of goodwill, which resulted in an impairment charge of $55.9 million, recognized as impairment of goodwill within the consolidated statements of operations for the year ended December 31, 2016. As a result of this charge, we did not have any goodwill as of December 31, 2017 or 2016.

Impairment of Renewable Energy Facilities

During 2016, we began exploring a sale of substantially all of our portfolio of residential rooftop solar assets located in the United States through a strategic sales process, and these assets were determined to meet the criteria to be classified as held for sale during the fourth quarter of 2016. Our analysis indicated that the carrying value of the assets exceeded the fair value less costs to sell, and thus an impairment charge of $15.7 million was recognized within impairment of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2016. We also recorded a $3.3 million charge within impairment of renewable energy facilities for the year ended December 31, 2016 due to the decision to abandon certain residential construction in progress assets that were not completed by SunEdison as a result of the SunEdison Bankruptcy.

We sold our remaining 0.3 MW of residential assets during the third quarter of 2017. Prior to the sale, we 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 our consolidated statements of operations for the year ended December 31, 2017.

Depreciation, Accretion and Amortization Expense

Depreciation, accretion and amortization expense increased by $3.4 million during the year ended December 31, 2017, compared to the same period in 2016. This increase was primarily the result of a change in the estimated useful lives of the major components of our wind power plants, which was effective October 1, 2016, and the impact of capital additions placed in service during 2016. These increases were partially offset by a reduction in depreciation, accretion and amortization expense related to the classification of our U.K. Portfolio as held for sale as of the end of the first quarter of 2016.

Interest Expense, Net

Interest expense, net for the years ended December 31, 2017 and 2016 were as follows:    

	Year Ended December 31,
(In thousands)	2017		2016		Change
Corporate-level	$	114,166	$	127,469	$	(13,303	)
Non-recourse:
Solar	70,439		97,123		(26,684		)
Wind	77,398		85,744		(8,346		)
Total interest expense, net	$	262,003	$	310,336	$	(48,333	)

Interest expense, net decreased by $48.3 million during the year ended December 31, 2017, compared to the same period in 2016. Interest expense under corporate-level long-term debt agreements decreased $13.3 million primarily due to lower outstanding balances under the Revolver. Interest expense under our non-recourse long-term debt agreements decreased by $26.7 million and $8.3 million for our Solar and Wind segments, respectively. The decrease at our Solar segment is

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primarily due to the recognition of $21.8 million of additional expense in the prior year as a result of the discontinuation of hedge accounting for the U.K. Portfolio's interest rate swaps in the second quarter of 2016, as well as lower interest expense in 2017 as a result of the sale of the U.K. Portfolio in May of 2017. The decrease at our Wind segment is primarily due to a $9.8 million decrease resulting from a $100.0 million prepayment of a non-recourse portfolio term loan in June 2017 and the repayment of the remaining outstanding principal balance on November 8, 2017.

Loss on Extinguishment of Debt, net

We incurred a net loss on extinguishment of debt of $81.1 million for the year ended December 31, 2017, compared to a loss of $1.1 million during the same period in the prior year. As discussed in Note 10. Long-term Debt to our consolidated financial statements, we issued the Senior Notes due 2023 and the Senior Notes due 2028 and used the proceeds to redeem in full our existing Senior Notes due 2023. As a result, we recognized a $72.3 million loss on extinguishment of debt during the year ended December 31, 2017, consisting of the $50.7 million make-whole premium and the write-off of $21.6 million of unamortized deferred financing costs and debt discounts for the Senior Notes due 2023 as of the redemption date. On October 17, 2017, we terminated the Old Revolver and entered into the Revolver. As a result of this exchange, we recognized a $4.5 million loss on extinguishment of debt due to the write-off of unamortized deferred financing costs for the Old Revolver as of the termination date. The remaining loss on extinguishment of debt for 2017 was due to other reductions in borrowing capacity for the Old Revolver during 2017 prior to its termination and prepayments and a final repayment of a non-recourse portfolio term loan prior to the date a change of control would have occurred.

The loss on extinguishment of debt of $1.1 million for the year ended December 31, 2016 was driven by a reduction in borrowing capacity for the Old Revolver and corresponding write-off of a portion of the unamortized deferred financing costs, due to entering into the consent agreement and ninth amendment to the terms of the Old Revolver and a waiver agreement with the requisite lenders pertaining to third quarter reporting deliverables and compliance.

Gain on Sale of Renewable Energy Facilities

On May 11, 2017, we announced that Terra Operating LLC completed its previously announced sale of 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. We recognized a gain on the sale of $37.1 million within gain on sale of renewable energy facilities in the consolidated statements of operations for the year ended December 31, 2017.

(Gain) Loss on Foreign Currency Exchange, net

We incurred a net gain on foreign currency exchange of $6.1 million for the year ended December 31, 2017 as compared to a net loss on foreign currency exchange of $13.0 million for the year ended December 31, 2016. The net gain for the year ended December 31, 2017 was primarily due to a $7.1 million unrealized gain on the remeasurement of intercompany loans (which were primarily denominated in Canadian dollars as of the end of 2017), offset by $1.0 million of realized and unrealized net losses on foreign currency derivatives. The net loss for the year ended December 31, 2016 was primarily due to a $14.4 million unrealized loss on the remeasurement of intercompany loans (which were primarily denominated in British pounds in 2016), which was offset by $1.3 million of realized and unrealized net gains on foreign currency derivatives.

Loss on Investments and Receivables - Affiliate

We incurred a net loss on investments and receivables - affiliate of $1.8 million due to the write-off of receivables from SunEdison upon the consummation of the Merger and the effectiveness of the Settlement Agreement with SunEdison on October 16, 2017. During the year ended December 31, 2016, we recognized a $3.3 million loss related to recording a bad debt reserve for outstanding receivables from debtors in the SunEdison Bankruptcy. 

Other (Income) Expenses, net

We recognized $5.0 million of other income, net for the year ended December 31, 2017 compared to $2.2 million of other expenses, net for the year ended December 31, 2016. We entered into a settlement agreement with insurers of one of our wind power plants with respect to insurance proceeds related to a battery fire that occurred at the wind power plant in 2012. We received $5.3 million of proceeds from this settlement in the fourth quarter of 2017. Other expenses, net for 2016 was primarily due to a $4.2 million loss on investment offset by $2.0 million of other miscellaneous income.

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Income Tax (Benefit) Expense

Income tax benefit from continuing operations was $19.6 million for the year ended December 31, 2017, compared to income tax expense of $2.7 million during the same period in 2016. For the year ended December 31, 2017, the overall effective tax rate of 9.0% was lower than the statutory rate of 35% primarily due to loss allocated to the recording of a valuation allowance on certain tax benefits attributed to the Company, loss allocated to non-controlling interests, the revaluation of deferred federal and state tax balances and the effect of foreign and state taxes. As of December 31, 2017, in most jurisdictions in which we operate, we were in a net deferred tax asset position. A valuation allowance is recorded against the deferred tax assets primarily because of the history of losses in those jurisdictions. Additionally, as discussed in Government Incentives and Legislation within Item 1. Business, the Tax Act was enacted on December 22, 2017, which provides that all U.S. corporations will be taxed at a flat rate of 21% for taxable years beginning January 1, 2018. For certain deferred tax assets and deferred tax liabilities, we recorded a provisional net adjustment that increased the deferred tax benefit by $5.0 million for the year ended December 31, 2017.

Net Loss Attributable to Non-Controlling Interests

Net loss attributable to non-controlling interests, including redeemable non-controlling interests, was $76.1 million for the year ended December 31, 2017. This was the result of a $27.5 million loss attributable to SunEdison's interest in Terra LLC's net loss during the period prior to the consummation of the Merger on October 16, 2017, and a $48.6 million loss attributable to project-level tax equity partnerships. Net loss attributable to non-controlling interests, including redeemable non-controlling interests, was $120.2 million for the year ended December 31, 2016. This was the result of a $65.7 million loss attributable to SunEdison's interest in Terra LLC's net income during the year ended December 31, 2016 and a $54.5 million loss attributable to project-level tax equity partnerships.

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 asset’s contracted life at investment grade metrics, as well as retained cash flows from operations and issuance of equity securities through public markets.

The following table summarizes the total capitalization and debt to capitalization percentage as of December 31, 2018 and 2017:

	As of December 31,
(In thousands)	2018			2017
Revolving Credit Facilites1	$	377,000		$	60,000
Senior Notes2	1,500,000			1,500,000
Term Loan3	346,500			350,000
Non-recourse long-term debt, including current portion4	3,573,436			1,732,516
Long-term indebtedness, including current portion5	5,796,936			3,642,516
Total stockholders’ equity and redeemable non-controlling interests	2,768,417			2,422,372
Total capitalization	$	8,565,353		$	6,064,888
Debt to total capitalization	68		%	60		%

———

(1) Represents $377.0 million drawn under our Revolver, and does not include the $99.5 million of outstanding project-level letters of credit. On October 5, 2018, Terra Operating LLC entered into an amendment to the Revolver. On October 26, 2018, Saeta repaid the outstanding balance under its revolver and terminated such revolving credit facility.

(2) Represents corporate senior notes. See the Financing Activities section below for discussion regarding 2018 activity.

(3) Represents senior secured term loan facility. See the Financing Activities section below for further discussion.

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

(5) Represents total principal due for long-term debt and financing lease obligations, including the current portion, which excludes $35.1 million and $43.7 million of unamortized debt discounts and deferred financing costs as of December 31, 2018 and 2017, respectively.

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Liquidity Position

We operate with sufficient liquidity to enable us to fund dividends, 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 Sponsor Line and Revolver 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.

The following table summarizes corporate liquidity and available capital as of December 31, 2018 and 2017:

	As of December 31,
(In thousands)	2018			2017
Unrestricted corporate cash	$	52,506		$	46,810
Project-level distributable cash	18,414			21,180
Cash available to corporate	70,920			67,990
Credit facilities:
Committed revolving credit facilities1	600,000			450,000
Drawn portion of revolving credit facilities	(377,000		)	(60,000		)
Revolving line of credit commitments	(99,487		)	(102,637		)
Undrawn portion of Sponsor Line2	500,000			500,000
Available portion of credit facilities	623,513			787,363
Corporate liquidity	$	694,433		$	855,353
Other project-level unrestricted cash	177,604			60,097
Project-level restricted cash3	144,285			96,700
Available capital	$	1,016,322		$	1,012,150

———

(1) On February 6, 2018, Terra Operating LLC elected to increase the total borrowing capacity of the Revolver from $450.0 million to $600.0 million. On October 5, 2018, Terra Operating LLC entered into an amendment to the Revolver, as discussed in the Financing Activities section below.

(2) Represents a $500.0 million secured revolving Sponsor Line (as defined below) credit facility that may only be used to fund all or a portion of certain funded acquisitions or growth capital expenditures. During the year ended December 31, 2018, we drew and repaid $86.0 million under the Sponsor Line. As discussed in the Financing Activities section below, the Sponsor Line may only be used to fund all or a portion of certain funded acquisitions or growth capital expenditures.

(3) Represents short-term and long-term restricted cash and includes $2.3 million of cash trapped at our project-level subsidiaries as of December 31, 2018, which is presented as current restricted cash as the cash balances were subject to distribution restrictions related to debt defaults that existed as of the balance sheet date (seeNote 2. Summary of Significant Accounting Policies to our consolidated financial statements for additional details).

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Financing Activities

Revolver

On October 17, 2017, Terra Operating LLC 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 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 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 (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 (as defined as defined in Note10.Long-Term Debt to our consolidated financial statements).

During the year ended December 31, 2017, (i) an initial draw of $250.0 million was used to refinance our Old Revolver (as defined in Note10.Long-Term Debt to our consolidated financial statements) and (ii) two additional draws of $15.0 million each were used for other general corporate purposes and working capital requirements of Terra Operating LLC. During the year ended December 31, 2018, we made (i) a draw of $442.0 million to fund a portion of the acquisition of Saeta (see Note 4. Acquisitions and Dispositions to our consolidated financial statements) and (ii) additional draws of $217.0 million for other working capital requirements. We made repayments of $362.0 million and $205.0 million under the Revolver during the years ended December 31, 2018 and 2017, respectively.

Senior Notes Supplemental Indentures, New Issuances and Redemption

On August 11, 2017, Terra Operating LLC completed a consent solicitation from holders of its Old Senior Notes due 2023 (as defined in Note 10.Long-Term Debt to our consolidated financial statements) and its Senior Notes due 2025 (as defined in Note10.Long-Term Debt to our consolidated financial statements) to obtain a waiver of the requirement to make an offer to repurchase the respective Old Senior Notes upon the occurrence of a change of control that would result from the consummation of the Merger. Terra Operating LLC received consents from the holders of a majority of the aggregate principal amount of each series of the Old Senior Notes outstanding as of the record date and paid a consent fee to each consenting holder of $1.25 per $1,000 principal amount of such series of the Senior Notes for which such holder delivered its consent. Upon the closing of the Merger, Terra Operating LLC also paid a success fee of $1.25 per $1,000 principal amount of each series of the Senior Notes for which such consenting holder delivered its consent.

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 $700.0 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 proceeds to redeem in full its existing Old Senior Notes due 2023, of which $950.0 million remained outstanding, at a redemption price that included a make-whole premium of $50.7 million, plus accrued and unpaid interest, and to repay $150.0 million of revolving loans outstanding under the Revolver.

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 make LIBOR loans to us during a period not to exceed three years from the effective date of the Sponsor Line

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(subject to acceleration for certain specified events). We may only use the revolving Sponsor Line to fund all or a portion of certain funded acquisitions or growth capital expenditures.  The Sponsor Line will terminate, and all obligations thereunder will 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, 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 million that were used to fund the acquisition of Saeta, which amounts were repaid in full as of December 31, 2018. We did not make any draws on the Sponsor Line during the year ended December 31, 2017.

Term Loan

On November 8, 2017, Terra Operating LLC entered into a 5-year $350.0 million senior secured term loan (the “Term Loan”), which was used to repay outstanding borrowings under the Midco Portfolio Term Loan (as defined in Note 10.Long-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 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 subsequent to 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 on the Term Loan was reduced by 0.75% per annum. We recognized a $1.5 million loss during the year ended December 31, 2018 as a result of this amendment, representing write offs of certain debt financing costs. On March 8, 2019, we entered into interest rate swap agreements with counterparties to hedge the variable Eurodollar base rate associated with the interest payments on the entire principal of our Term Loan, paying an average fixed rate of 2.54%. In return, the counterparties agreed to pay us the variable Eurodollar base rate payments due to the lenders until maturity.

Non-recourse Project Financing

On June 6, 2018, one of our subsidiaries entered into a new non-recourse debt financing agreement whereby it issued $83.0 million of 4.59% senior notes maturing in 2040, secured by approximately 73 MW of utility-scale solar power plants located in Utah, Florida, Nevada and California. The proceeds of this financing were used to pay down the Revolver, which was drawn to fund a portion of the purchase price for our acquisition of Saeta.

On September 28, 2018, one of our subsidiaries entered into a new non-recourse debt financing agreement whereby it issued $78.8 million of 4.64% senior notes maturing in 2032, secured by approximately 51 MW of utility-scale and distributed-generation solar power plants located in New York, New Jersey, Massachusetts, North Carolina, Colorado and California. The majority of the proceeds of this financing were used to repay a portion of the Revolver in October 2018.

On September 28, 2018, one of our subsidiaries in Spain entered into a new non-recourse debt refinancing arrangement whereby it issued €50.0 million of notes secured by 48 MW of utility-scale wind power plants located in Southern Spain. The notes consist of €30.0 million Tranche A (the equivalent of approximately $35.0 million on the closing date) maturing in 9.5 years and €20.0 million Tranche B (the equivalent of approximately $23.0 million on the closing date) maturing in 12.5 years. Tranche A bears interest at a rate per annum equal to six-month Euro Interbank Offered Rate (“Euribor”) plus an applicable margin of 1.70%. Tranche B bears a fixed interest rate of 2.84%. We entered into interest rate swap agreements with counterparties to economically hedge greater than 90% of the cash flows associated with the debt, paying a fixed rate of 3.78% for the first five years and 1.15% for the following two years.

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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, 2018, 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)	2019		2020		2021		2022		2023		Thereafter		Total
Maturities of long-term debt1	$	276,480	$	248,981	$	257,665	$	754,102	$	1,221,102	$	3,044,776	$	5,803,106

—————

(1) Represents the contractual principal payment due dates for our long-term debt and does not reflect the reclassification of $166.4 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).

Cash Dividends to Investors

The following table presents cash dividends declared and paid on Class A common stock during the year ended December 31, 2018:

	Type	Dividends per Share		Declaration Date	Record Date	Payment Date
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

On October 6, 2017, our Board declared the payment of the Special Dividend (as defined in Note 14. Stockholder’s Equity to our consolidated financial statements) 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 our issued and outstanding Class A shares, Class A shares issued to SunEdison pursuant to the Settlement Agreement and Class A shares underlying our outstanding restricted stock units under our 2014 Second Amended and Restated Long-Term Incentive Plan (the “2014 LTIP”). The Special Dividend, which was paid on October 17, 2017, represented the only dividend payment during the year ended December 31, 2017.

On March 13, 2019, our Board declared a quarterly dividend with respect to our Class A common stock of $0.2014 per share. The dividend is payable on March 29, 2019 to stockholders of record as of March 24, 2019.

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.

SunEdison transferred all of the outstanding IDRs of Terra LLC held by SunEdison or certain of its affiliates to Brookfield IDR Holder, an indirect wholly-owned subsidiary of Brookfield, 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, resets the IDR thresholds of Terra LLC to establish a first distribution threshold of $0.93 per share of Class A common stock and a second distribution threshold of $1.05 per share of Class A common stock. As a result of this amendment and restatement, amounts distributed from Terra LLC will be distributed on a quarterly basis as follows:

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• first, to the Company in an amount equal to our 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 us in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Class A common stock of $0.93 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Class A common stock) if such amount were distributed to all holders of shares of Class A 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 us in respect of the taxable income attributable to such distribution, in a distribution to holders of shares of Class A common stock of an additional $0.12 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Class A common stock) if such amount were distributed to all holders of shares of Class A common stock; and

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

We did not make any IDR payments during the years ended December 31, 2018 and 2017.

Cash Flow Discussion

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

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

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

(In thousands)	Year Ended December 31,
	2018			2017			Change
Net cash provided by operating activities	$	253,201		$	67,197		$	186,004
Net cash (used in) provided by investing activities	(858,998		)	206,272			(1,065,270		)
Net cash provided by (used in) financing activities	782,501			(789,513		)	1,572,014

Net Cash Provided By Operating Activities

Net cash provided by operating activities for the year ended December 31, 2018 was $253.2 million as compared to $67.2 million for the same period in the prior year. The increase in operating cash flow of $186.0 million was primarily driven by a $169.9 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) primarily driven by the acquisition of Saeta in June of 2018. In addition, the timing of sales and collections resulted in a $15.5 millionincrease in cash receipts related to accounts receivable. Total operating costs (excluding non-cash items) decreased by $28.0 million for the year ended December 31, 2018 compared to the prior year primarily due to the payment of $27.0 million of success-based advisory fees upon the consummation of the Merger in the fourth quarter of 2017. The timing of payments related to accounts payable, accrued expenses and other current liabilities resulted in a $23.8 millionincrease in operating cash flow primarily as a result of the increase in accrued interest on our Senior Notes due 2023 and Senior Notes due 2028. The interest payments on these Senior Notes are due in January of 2019 as a result of the refinancing that occurred in the fourth quarter of 2017.

Net Cash (Used In) Provided by Investing Activities

Net cash used in investing activities for the year ended December 31, 2018 was $859.0 million, which was primarily due to: (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.

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Net Cash Provided by Financing Activities

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 dividend payments 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, 2018:

	Payment due by Period
Contractual Cash Obligations (in thousands)	2019		2020		2021		2022		2023		Thereafter		Total
Long-term debt (principal)1	$	270,889	$	243,511	$	252,001	$	746,872	$	1,218,092	$	2,994,675	$	5,726,040
Long-term debt (interest)2	277,623		267,153		252,926		240,272		182,363		796,346		2,016,683
Financing lease obligations	5,591		5,470		5,664		7,230		3,010		50,101		77,066
Operating leases	20,002		20,005		20,241		20,410		20,577		331,425		432,660
Purchase obligations3	32,457		31,533		16,696		12,135		10,426		64,292		167,539
Brookfield MSA4	12,240		15,300		15,606		15,918		16,236		N/A4		75,300
Tracking accounts	597		1,018		1,094		1,174		1,261		38,667		43,811
Other	2,431		2,431		1,545		1,545		—		—		7,952
Total contractual obligations	$	621,830	$	586,421	$	565,773	$	1,045,556	$	1,451,965	$	4,275,506	$	8,547,051

———

(1) Represents the contractual principal payment due dates for our long-term debt and does not reflect the reclassification of $19.9 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 fixed rate interest and variable rate interest using December 31, 2018 rates.

(3) Consists of contractual payments due for third party operation and maintenance services and asset management services.

(4) Represents the fixed component of the base management fee owed pursuant to the master services agreement with Brookfield and certain of its affiliates for the management and administrative services to be provided by Brookfield and certain of its affiliates to us. 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 19. 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 18. Commitments and Contingencies to our consolidated financial statements included in this Annual Report on Form 10-K 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 have 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 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 management in its 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, with the exception of 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.

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 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 sheet due to the recognition

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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 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. An impairment charge is measured as the difference between an asset's carrying amount and its fair value. 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, we recognized a $15.2 million impairment charge related to an operating project within its 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 its portfolio of residential rooftop solar assets. Impairment charges are reflected within impairment of renewable energy facilities in the consolidated statements of operations (see Note 5. Renewable Energy Facilities for further discussion). There were no impairments of renewable energy facilities or intangible assets recognized during the year ended December 31, 2016.

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.

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.

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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 23 to 30 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 21 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 on Form 10-K 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.

Interest Rate Risk

As of December 31, 2018, the estimated fair value of our debt was $5,789.7 million and the carrying value of our debt was $5,761.8 million. We estimate that a hypothetical 100 bps, or 1%, increase or decrease in market interest rates would have decreased or increased the fair value of our long-term debt by $88.1 million and $96.6 million, respectively.

As of December 31, 2018, our corporate-level debt consisted of the Senior Notes due 2023 (fixed rate), the Senior Notes due 2025 (fixed rate), the Senior Notes due 2028 (fixed rate), the Revolver (variable rate) and the Term Loan (variable rate). Additionally, during the year ended December 31, 2018, we drew and repaid $86.0 million under the Sponsor Line (variable rate). On March 8, 2019, we entered into interest rate swap agreements with counterparties to hedge the variable Eurodollar base rate associated with the interest payments on the entire principal of our Term Loan, paying an average fixed rate of 2.54%. In return, the counterparties agreed to pay us the variable Eurodollar base rate payments due to the lenders until maturity. A hypothetical increase or decrease in interest rates by 1% would have increased or decreased interest expense related to our Revolver, Term Loan and Sponsor Line by $6.2 million for the year ended December 31, 2018.

As of December 31, 2018, our non-recourse permanent financing debt was at both fixed and variable rates. 39% of the $3,496.4 million balance had a fixed interest rate and the remaining 61% of the balance had a variable interest rate. We have entered into interest rate derivatives to swap a 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 $56.8 million for the year ended December 31, 2018.

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Foreign Currency Risk

During the year ended December 31, 2018, 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, Canadian dollars and British pounds. The PPAs, operating and maintenance agreements, financing arrangements and other contractual arrangements relating to our current portfolio are denominated in U.S. dollars, Euro, Canadian dollars and British pounds.

We use currency forward 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 contracts to reduce risks arising from the change in fair value of certain assets, liabilities and intercompany loans denominated in Euro.

We use foreign currency forward contracts to hedge portions of our net investment positions in certain subsidiaries with Euro and Canadian dollar functional currencies and to manage our 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 accumulated other comprehensive income (“AOCI”). 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 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 $7.1 million for the year ended December 31, 2018. 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 pertaining to commodity swaps not designated as hedges would have decreased or increased our earnings by $12.7 million or $13.5 million for the year ended December 31, 2018, respectively.

Liquidity Risk

Our principal liquidity requirements are to finance current operations, service debt and to fund cash dividends to investors. Changes in operating plans, lower than anticipated electricity sales, increased expenses, acquisitions or other events may cause management 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 management's control.

Counterparty Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by offtake counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. 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, 2018, 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 each region 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.

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Customer Concentration

For the year ended December 31, 2018, we earned an aggregate of $186.7 million from the Spanish Electricity System, including $127.3 million from the Comisión Nacional de los Mercados y la Competencia (“CMNC”), which represents 16.7% of our 2018 consolidated operating revenues. The role of the CMNC is to collect funds payable, mainly from the tariffs to end user customers, and is responsible for the calculation and the settlement of regulated payments. We believe this concentration risk 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. Other than the CMNC in Spain, there is no other single customer from which we generated more than 10% of our revenues for the year ended December 31, 2018. In California, where a portion of our solar generation fleet is located, we generated certain revenues from three public utilities located in the state. These three public utilities, in aggregate, accounted for approximately 13.6% of our consolidated operating revenues for the year ended December 31, 2018.

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 on Form 10-K 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 2018 and 2017 are included in Note22. Quarterly Financial Information (Unaudited) to our consolidated financial statements in this Annual Report on Form 10-K.

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 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 Form 10-K, 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, 2018, 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, 2018, 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 2018, 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 those 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 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.

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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, 2018, 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, 2018, 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 of Saeta, which was acquired on June 12, 2018. As of December 31, 2018 and for the year ended December 31, 2018, total assets and total revenues subject to Saeta’s internal control over financial reporting represented approximately 35.7% and 28.9% of the Company’s consolidated total assets and total 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. In 2017, in making its assessment, management concluded that there were material weaknesses in our internal control over financial reporting.

2018 Remediation Activities

In response to the material weaknesses identified in our Annual Report on Form 10-K for the year ended December 31, 2017, the Company performed the following remediation activities in 2018:

• We revised our organization structure and hired dedicated permanent accounting, finance and IT personnel, including senior management, with assigned responsibility and accountability for financial reporting processes and internal controls. Further, we provided U.S. GAAP and internal controls training for all employees and remaining contractors involved with our internal control over financial reporting processes.

• We performed a fraud risk assessment process focused on identifying and analyzing risks of financial misstatement due to error and/or fraud, including management override of controls.

• We hired a senior internal audit resource and strengthened the internal audit function through increased interaction and engagement with the internal audit team of our Sponsor, Brookfield. A company-wide risk assessment has been completed and a risk-based internal audit plan has been developed that is responsive to the risks that were identified in the company-wide risk assessment and will assist in monitoring the Company’s adherence to its policies and procedures.

• We conducted a detailed review and re-documentation of key policies, business processes and controls and have made significant control design changes to ensure that control objectives are met. We have updated many of our financial reporting policies and procedures and enhanced management's self-assessment and testing for internal controls.

• We enhanced the information and communication processes to ensure the organization communicates information internally in a timely manner, including information regarding objectives, responsibilities and the functioning of internal controls over financial reporting. These enhancements include more rigorous analysis of the Company’s financial results versus its budgets and operating plans, more frequent discussion of significant business transactions and the impact of these transactions on the Company’s financial reporting, and improving communication to employees regarding their responsibilities for ensuring that effective internal controls are maintained.

• We established information technology and other critical systems infrastructure, and have enhanced the information technology control framework to support all business applications and infrastructure. We obtained and evaluated Service Organization Control reports from outside service providers for key applications utilized in financial reporting to ensure controls at the service organizations, in combination with the Company’s own controls, effectively achieve the Company’s objectives and assertions related to financial reporting.

• We implemented an accounting system with appropriate segregation of duties and approval workflows, which also enables a more effective procurement and accounts payable process with system controls for the review, approval and appropriate recording of expenditures on a timely basis.

• We standardized aspects of the account reconciliation process to ensure completeness, existence and accuracy of account balances on a timely basis.

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• We developed policies and procedures for treatment and recognition of changes to renewable energy facilities’ account balances, including process level review controls over validation of existence of assets, accumulated depreciation and depreciation, accretion and amortization expense.

Material Weaknesses in Internal Control

While we believe we have improved our organizational capabilities, the full impact of these changes had not been realized by December 31, 2018 and certain remediation activities are continuing to take place in 2019. Process-level and management review controls over certain manual financial reporting processes were not effective. Additionally, although the Company implemented revenue control enhancements in the third and fourth quarters of 2018, there was insufficient time to demonstrate full remediation of monthly and quarterly controls by December 31, 2018.

As of December 31, 2018, management 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.

• The Company did not have effective controls over the completeness, existence, and accuracy of revenues and deferred revenue and the completeness, existence, accuracy and valuation of accounts receivable.

Due to the existence of the above material weaknesses, our management has concluded that our internal control over financial reporting was not effective as of December 31, 2018. 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, 2018 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report, which appears herein.

Remediation Plan

We 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 began the process of implementing additional consolidation, treasury, and lease accounting related financial systems, each of which is expected to increase the efficiency of processing transactions, produce accurate and timely information in order to address various operational and compliance needs, and reduce our reliance on end-user computing spreadsheets.

• We are continuing to enhance revenue controls that were implemented in 2017 and 2018, as well as exploring opportunities to automate system journals and new applications to support invoicing and the sourcing of revenue data to reduce the reliance on manual controls.

• We are enhancing the review controls over the application of GAAP and accounting measurements for significant accounts, transactions and related financial statement disclosures by adding incremental resources and providing specialized/technical training to strengthen our skills to support our controllership function. We are also implementing additional controls and enhancing existing controls that support management’s assertions with respect to the completeness, accuracy and validity of complex accounting measurements on a timely basis.

Management has made significant progress with the Company’s remediation plans and will continue to take measures in 2019 to remediate these material weaknesses. In addition, under the direction of the Audit Committee of the Board of Directors, management 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.

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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 working to have these material weaknesses remediated as soon as possible. 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 Form 10-K. 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

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, 2018 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

Certain information required by Part III is omitted from this Form 10-K 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, or the 2019 Proxy Statement, within 120 days after the end of the fiscal year covered by this Form 10-K, 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 2019 Proxy Statement and is incorporated by reference herein.

Item 11. Executive Compensation.

The information required under this Item 11 will be included in our 2019 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 2019 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 2019 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 2019 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	80
Report of Independent Registered Public Accounting Firm - Consolidated Financial Statements	81
Report of Predecessor Independent Registered Public Accounting Firm - Consolidated Financial Statements	82
Consolidated Statements of Operations	83
Consolidated Statements of Comprehensive Loss	84
Consolidated Balance Sheets	85
Consolidated Statements of Stockholders' Equity	86
Consolidated Statements of Cash Flows	88
Notes to Consolidated Financial Statements	90

(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:

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

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, 2018, 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, 2018, 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 Saeta Yield S.A., which is included in the 2018 consolidated financial statements of the Company and constituted 36% of total assets as of December 31, 2018 and 29% of 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 Saeta Yield S.A.

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 significant accounts, transactions and related financial statement disclosures.

• The Company did not have effective controls over the completeness, existence, and accuracy of revenues and deferred revenue and the completeness, existence, accuracy and valuation of accounts receivable.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2018 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 2018 consolidated financial statements, and this report does not affect our report dated March 15, 2019, which expressed an unqualified opinion thereon, based on our audit and the report of the other auditors.

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 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 15, 2019

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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 sheet of TerraForm Power Inc. and subsidiaries (the Company) as of December 31, 2018 the related consolidated statements of operations, comprehensive loss, stockholders' equity and cash flows for the year ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audit 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, 2018, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

We did not audit the 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, 2018, 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 15, 2019, 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.

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 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit 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 audit 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 audit and the report of other auditors provides a reasonable basis for our opinion.

/s/ Ernst & Young LLP

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

New York, New York

March 15, 2019

81

Report of Independent Registered Public Accounting Firm

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

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of TerraForm Power, Inc. and subsidiaries (the Company) as of December 31, 2017, the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for each of the years in the two‑year period 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 financial position of the Company as of December` 31, 2017, and the results of its operations and its cash flows for each of the years in the two‑year period 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 ninth paragraph in

Note 11 and the fourth and fifth paragraphs in Note

17, as to which the date is March 15, 2019

82

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Year Ended December 31,
	2018			2017			2016
Operating revenues, net	$	766,570		$	610,471		$	654,556
Operating costs and expenses:
Cost of operations	220,907			150,733			113,302
Cost of operations - affiliate	—			17,601			26,683
General and administrative expenses	87,722			139,874			89,995
General and administrative expenses - affiliate	16,239			13,391			14,666
Acquisition costs	7,721			—			2,743
Acquisition costs - affiliate	6,925			—			—
Impairment of goodwill	—			—			55,874
Impairment of renewable energy facilities	15,240			1,429			18,951
Depreciation, accretion and amortization expense	341,837			246,720			243,365
Total operating costs and expenses	696,591			569,748			565,579
Operating income	69,979			40,723			88,977
Other expenses (income):
Interest expense, net	249,211			262,003			310,336
Loss on extinguishment of debt, net	1,480			81,099			1,079
Gain on sale of renewable energy facilities	—			(37,116		)	—
(Gain) loss on foreign currency exchange, net	(10,993		)	(6,061		)	13,021
Loss on investments and receivables - affiliate	—			1,759			3,336
Other (income) expenses, net	(4,102		)	(5,017		)	2,218
Total other expenses, net	235,596			296,667			329,990
Loss before income tax (benefit) expense	(165,617		)	(255,944		)	(241,013		)
Income tax (benefit) expense	(12,290		)	(19,641		)	2,734
Net loss	(153,327		)	(236,303		)	(243,747		)
Less: Net income attributable to redeemable non-controlling interests	9,209			1,596			6,482
Less: Net loss attributable to non-controlling interests	(174,916		)	(77,745		)	(126,718		)
Net income (loss) attributable to Class A common stockholders	$	12,380		$	(160,154	)	$	(123,511	)
Weighted average number of shares:
Class A common stock - Basic and diluted	182,239			103,866			90,815
Earnings (loss) per share:
Class A common stock - Basic and diluted	$	0.07		$	(1.61	)	$	(1.40	)
Dividend declared per share:
Class A common stock	$	0.76		$	1.94		$	—

83

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

	Year Ended December 31,
	2018			2017			2016
Net loss	$	(153,327	)	$	(236,303	)	$	(243,747	)
Other comprehensive (loss) income, net of tax:
Foreign currency translation adjustments:
Net unrealized (loss) gain arising during the period	(9,517		)	10,300			(15,039		)
Reclassification of net realized loss into earnings1	—			14,741			—
Hedging activities:
Net unrealized gain (loss) arising during the period	198			17,612			(86		)
Reclassification of net realized (gain) loss into earnings2	(4,442		)	(2,247		)	15,967
Other comprehensive income, net of tax	(13,761		)	40,406			842
Total comprehensive loss	(167,088		)	(195,897		)	(242,905		)
Less comprehensive income (loss) attributable to non-controlling interests:
Net income attributable to redeemable non-controlling interests	9,209			1,596			6,482
Net loss attributable to non-controlling interests	(174,916		)	(77,745		)	(126,718		)
Foreign currency translation adjustments	—			8,665			(4,639		)
Hedging activities	(777		)	5,992			5,469
Comprehensive loss attributable to non-controlling interests	(166,484		)	(61,492		)	(119,406		)
Comprehensive loss attributable to Class A common stockholders	$	(604	)	$	(134,405	)	$	(123,499	)

———

(1) Represents reclassification of the accumulated foreign currency translation loss for substantially all of the Company’s portfolio of solar power plants located in the United Kingdom, as the Company’s sale of these facilities closed in the second quarter of 2017 as discussed in Note 4.Acquisitions and Dispositions. 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) Includes $16.9 million loss reclassification for the year ended December 31, 2016 that occurred subsequent to the Company’s discontinuation of hedge accounting for interest rate swaps pertaining to variable rate non-recourse debt for substantially all of the Company’s portfolio of solar power plants located in the United Kingdom as discussed in Note 12. Derivatives. As discussed above, the Company’s sale of these facilities closed in the second quarter of 2017.

84

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

	As of December 31,
	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	248,524		$	128,087
Restricted cash	27,784			54,006
Accounts receivable, net	145,161			89,680
Prepaid expenses and other current assets	79,520			65,393
Due from affiliate	196			4,370
Total current assets	501,185			341,536
Renewable energy facilities, net, including consolidated variable interest entities of $3,064,675 and $3,273,848 in 2018 and 2017, respectively	6,470,026			4,801,925
Intangible assets, net, including consolidated variable interest entities of $751,377 and $823,629 in 2018 and 2017, respectively	1,996,404			1,077,786
Goodwill	120,553			—
Restricted cash	116,501			42,694
Other assets	125,685			123,080
Total assets	$	9,330,354		$	6,387,021
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 $64,251 and $84,691 in 2018 and 2017, respectively	$	464,332		$	403,488
Accounts payable and accrued expenses, including consolidated variable interest entities of $55,446 and $32,624 in 2018 and 2017, respectively	177,089			85,693
Other current liabilities	38,244			2,845
Deferred revenue	1,626			17,859
Due to affiliates	6,991			3,968
Total current liabilities	688,282			513,853
Long-term debt and financing lease obligations, less current portion, including consolidated variable interest entities of $885,760 and $833,388 in 2018 and 2017, respectively	5,297,513			3,195,312
Deferred revenue, less current portion	12,090			38,074
Deferred income taxes	178,849			24,972
Asset retirement obligations, including consolidated variable interest entities of $86,456 and $97,467 in 2018 and 2017, respectively	212,657			154,515
Other liabilities	172,546			37,923
Total liabilities	6,561,937			3,964,649
Redeemable non-controlling interests	33,495			34,660
Stockholders’ equity:
Class A common stock, $0.01 par value per share, 1,200,000,000 shares authorized, 209,642,140 and 148,586,447 shares issued in 2018 and 2017, respectively, and 209,141,720 and 148,086,027 shares outstanding in 2018 and 2017, respectively	2,096			1,486
Additional paid-in capital	2,391,435			1,872,125
Accumulated deficit	(359,603		)	(387,204		)
Accumulated other comprehensive income	40,238			48,018
Treasury stock, 500,420 shares in 2018 and 2017	(6,712		)	(6,712		)
Total TerraForm Power, Inc. stockholders’ equity	2,067,454			1,527,713
Non-controlling interests	667,468			859,999
Total stockholders’ equity	2,734,922			2,387,712
Total liabilities, redeemable non-controlling interests and stockholders' equity	$	9,330,354		$	6,387,021

85

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, 2015	79,734	$	784	60,364		$	604		$	1,267,484		$	(103,539	)	$	22,900		(122	)	$	(2,436	)	$	1,185,797		$	1,953,584		$	(182,024	)	$	(15,236	)	$	1,756,324		$	2,942,121
SunEdison exchange	12,162	122		(12,162	)	(122		)	181,045			—			—			—		—			181,045			(181,045		)	—			—			(181,045		)	—
Stock-based compensation	581	14		—		—			6,729			—			—			(132	)	(1,589		)	5,154			—			—			—			—			5,154
Net loss	—	—		—		—			—			(123,511		)	—			—		—			(123,511		)	—			(126,718		)	—			(126,718		)	(250,229		)
Acquisition accounting adjustment to non-controlling interest in acquired renewable energy facility	—	—		—		—			—			—			—			—		—			—			8,000			—			—			8,000			8,000
Repurchase of non-controlling interest in renewable energy facility	—	—		—		—			—			—			—			—		—			—			(486		)	—			—			(486		)	(486		)
Net SunEdison investment	—	—		—		—			16,372			—			—			—		—			16,372			9,028			—			—			9,028			25,400
Other comprehensive income	—	—		—		—			—			—			12			—		—			12			—			—			830			830			842
Sale of membership interests and contributions from non-controlling interests in renewable energy facilities	—	—		—		—			—			—			—			—		—			—			15,674			—			—			15,674			15,674
Distributions to non-controlling interests in renewable energy facilities	—	—		—		—			—			—			—			—		—			—			(13,020		)	—			—			(13,020		)	(13,020		)
Accretion of redeemable non-controlling interest	—	—		—		—			(3,962		)	—			—			—		—			(3,962		)	—			—			—			—			(3,962		)
Equity reallocation	—	—		—		—			(560		)	—			—			—		—			(560		)	560			—			—			560			—
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 Dividend 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 in renewable energy facilities	—	—		—		—			—			—			—			—		—			—			6,935			—			—			6,935			6,935
Distributions to non-controlling interests in renewable energy facilities	—	—		—		—			—			—			—			—		—			—			(23,345		)	—			—			(23,345		)	(23,345		)
Deconsolidation of non-controlling interest in renewable energy facility	—	—		—		—			—			—			—			—		—			—			(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

86

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, 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		)
Dividends	—	—		—	—		(135,234		)	—			—			—		—			(135,234		)	—			—			—			—			(135,234		)
Other comprehensive loss	—	—		—	—		—			—			(12,984		)	—		—			(12,984		)	—			—			(777		)	(777		)	(13,761		)
Contributions from non-controlling interests in renewable energy facilities	—	—		—	—		—			—			—			—		—			—			7,685			—			—			7,685			7,685
Distributions to non-controlling interests in renewable energy facilities	—	—		—	—		—			—			—			—		—			—			(24,128		)	—			—			(24,128		)	(24,128		)
Purchase of redeemable non-controlling interests in renewable energy facilities	—	—		—	—		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

———

(1) See Note 2. Summary of Significant Accounting Policies for discussion regarding the Company’s 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.

87

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities:
Net loss	$	(153,327	)	$	(236,303	)	$	(243,747	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, accretion and amortization expense	341,837			246,720			243,365
Amortization of favorable and unfavorable rate revenue contracts, net	38,767			39,576			40,219
Loss on extinguishment of debt, net	1,480			81,099			1,079
Gain on sale of renewable energy facilities	—			(37,116		)	—
Impairment of goodwill	—			—			55,874
Impairment of renewable energy facilities	15,240			1,429			18,951
Loss on disposal of property, plant and equipment	6,231			5,828			—
Amortization of deferred financing costs and debt discounts	11,009			23,729			24,160
Unrealized (gain) loss on interest rate swaps	(13,116		)	2,425			24,209
Loss on note receivable	4,510			—			—
Unrealized loss on commodity contract derivatives, net	4,497			6,847			11,773
Recognition of deferred revenue	(1,320		)	(18,238		)	(16,527		)
Stock-based compensation expense	257			16,778			6,059
Unrealized (gain) loss on foreign currency exchange, net	(12,899		)	(5,583		)	15,795
Loss on investments and receivables - affiliate	—			1,759			3,336
Deferred taxes	(14,891		)	(19,911		)	2,615
Other, net	—			(1,166		)	2,542
Changes in assets and liabilities, excluding the effect of acquisitions and divestitures:
Accounts receivable	12,569			(2,939		)	3,112
Prepaid expenses and other current assets	(5,512		)	803			(8,585		)
Accounts payable, accrued expenses and other current liabilities	(18,976		)	(42,736		)	(1,156		)
Due to affiliates, net	3,023			3,968			—
Deferred revenue	—			199			4,803
Other, net	33,822			29			3,932
Net cash provided by operating activities	253,201			67,197			191,809
Cash flows from investing activities:
Cash paid to third parties for renewable energy facility construction and other capital expenditures	(22,445		)	(8,392		)	(45,869		)
Proceeds from insurance reimbursement	1,543			—			—
Proceeds from the settlement of foreign currency contracts	47,590			—			—
Proceeds from sale of renewable energy facilities, net of cash and restricted cash disposed	—			183,235			—
Proceeds from energy state rebate and reimbursable interconnection costs	8,733			25,679			—
Other investing activities	—			5,750			—
Acquisitions of renewable energy facilities from third parties, net of cash and restricted cash acquired	(8,315		)	—			(4,064		)
Acquisition of Saeta business, net of cash and restricted cash acquired	(886,104		)	—			—
Net cash (used in) provided by investing activities	$	(858,998	)	$	206,272		$	(49,933	)

88

TERRAFORM POWER, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(CONTINUED)

	Year Ended December 31,
	2018			2017			2016
Cash flows from financing activities:
Proceeds from issuance of Class A common stock to affiliates	$	650,000		$	—		$	—
Proceeds from the Sponsor Line - affiliate	86,000			—			—
Repayments of the Sponsor Line - affiliate	(86,000		)	—			—
Repayment of the Old Senior Notes due 2023	—			(950,000		)	—
Proceeds from the Senior Notes due 2023	—			494,985			—
Proceeds from the Senior Notes due 2028	—			692,979			—
Proceeds from Term Loan	—			344,650			—
Term Loan principal repayments	(3,500		)	—			—
Old Revolver repayments	—			(552,000		)	(103,000		)
Revolver draws	679,000			265,000			—
Revolver repayments	(362,000		)	(205,000		)	—
Proceeds from borrowings of non-recourse long-term debt	236,251			79,835			86,662
Principal repayments on non-recourse long-term debt	(259,017		)	(569,463		)	(156,042		)
Debt premium prepayment	—			(50,712		)	—
Debt financing fees	(9,318		)	(29,972		)	(17,436		)
Sale of membership interests and contributions from non-controlling interests in renewable energy facilities	7,685			6,935			16,685
Purchase of membership interests and distributions to non-controlling interests in renewable energy facilities	(29,163		)	(31,163		)	(24,270		)
Net SunEdison investment	—			7,694			42,463
Due to/from affiliates, net	4,803			(8,869		)	(32,256		)
Payment of dividends	(135,234		)	(285,497		)	—
Recovery of related party short swing profit	2,994			—			—
Other financing activities	—			1,085			—
Net cash provided by (used in) financing activities	782,501			(789,513		)	(187,194		)
Net increase (decrease) in cash, cash equivalents and restricted cash	176,704			(516,044		)	(45,318		)
Net change in cash, cash equivalents and restricted cash classified within assets held for sale	—			54,806			(54,806		)
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(8,682		)	3,188			(10,072		)
Cash, cash equivalents and restricted cash at beginning of period	224,787			682,837			793,033
Cash, cash equivalents and restricted cash at end of period	$	392,809		$	224,787		$	682,837
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	250,734		$	260,685		$	257,269
Cash paid for income taxes	430			—			$	—
Schedule of non-cash activities:
Additions to renewable energy facilities in accounts payable and accrued expenses	4,000			$	1,622		$	—
Write-off of payables to SunEdison to additional paid-in capital	—			15,677			—
Additions of asset retirement obligation (ARO) assets and liabilities	—			—			2,132
Revisions in estimates for asset retirement obligations	—			—			(7,920		)
Adjustment to ARO related to change in accretion period	(15,734		)	—			(22,204		)
Issuance of class A common stock to affiliates for settlement of litigation	881			—			—
ARO assets and obligations from acquisitions	68,441			—			136
Long-term debt assumed in connection with acquisitions	1,932,743			—			—

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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 only material asset is an equity interest in TerraForm Power, LLC (“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. TerraForm Power is the managing member of Terra LLC and operates, controls and consolidates the business affairs of Terra LLC. 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.

Prior to the consummation of the Merger (as defined below) on October 16, 2017, TerraForm Power was a controlled affiliate of SunEdison, Inc. (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”), which is 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 Class A common stock.

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

On April 21, 2016, SunEdison, Inc. 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 (the “Merger 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 19. Related Parties and Note 10. Long-term Debt.

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

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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 14. Stockholders' Equity). SunEdison and certain of its affiliates also transferred all of the outstanding incentive distribution rights (“IDRs”) of Terra LLC held by SunEdison or certain of its affiliates to BRE Delaware, Inc. (the “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 19. 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 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.

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. As of December 31, 2018 and 2017, cash and cash equivalents included $177.0 million and $60.1 million, respectively, of unrestricted cash held at project-level subsidiaries, which was available for project expenses but not available for corporate use. 

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 financial statements. Restricted cash that is not expected to become unrestricted within the next twelve months is presented within non-current assets on the consolidated statements of financial position.

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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, 2018, 2017 and 2016.

(In thousands)	As of December 31,
	2018		2017		2016
Cash and cash equivalents	$	248,524	$	128,087	$	565,333
Restricted cash - current	27,784		54,006		114,950
Restricted cash - non-current	116,501		42,694		2,554
Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	392,809	$	224,787	$	682,837

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, 2018 and 2017. As a result, the Company reclassified $11.2 million and $18.8 million, respectively, of long-term restricted cash to current as of December 31, 2018 and 2017, 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. As of December 31, 2018 and 2017, $1.4 million and $21.7 million, respectively, of cash and cash equivalents was also reclassified to current restricted cash as the cash balances were subject to distribution restrictions related to debt defaults that existed as of the respective balance sheet date.

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 any write-offs as well as the allowance for doubtful accounts. 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. The allowance for doubtful accounts was $1.6 million and $1.7 million as of December 31, 2018 and 2017, respectively, and charges (reductions) to the allowance recorded within general and administrative expenses for the years ended December 31, 2018, 2017 and 2016 were $0.1 million, $(1.5) million and $0.5 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, 2018, 2017 and 2016.

Renewable Energy Facilities

Renewable energy facilities consist of solar generation 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 renewable energy facilities is recognized using the straight-line method over the estimated useful lives of the renewable energy facilities, which range from 23 to 30 years for the Company’s solar generation facilities. Effective October 1, 2016, the Company changed its estimates of the useful lives of the major components of its wind power plants to better reflect the estimated periods during which these major components will remain in service. These major components comprising the Company’s wind power plants had remaining useful lives ranging from 5 to 41 years and had an overall weighted average remaining useful life of 24 years as of October 1, 2016. This prospective change in estimate increased depreciation expense and net loss by $1.9 million for the year ended December 31, 2016. As of December 31, 2018 and 2017, they had a weighted average remaining useful life of 21 and 23 years, respectively.

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

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Finite-Lived Intangibles

The Company's finite-lived intangible assets and liabilities represent revenue contracts, consisting of long-term concessions and licensing contracts, power purchase agreements (“PPAs”), RECs, lease agreements and operations and maintenance (“O&M”) contracts that were obtained through third party acquisitions. The revenue contract intangibles are comprised of favorable and unfavorable rate PPAs and REC agreements and the in-place value of market rate PPAs. The lease agreement intangibles are comprised of favorable and unfavorable rate land leases, and the O&M contract intangibles consist of unfavorable rate O&M contracts. 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 concessions and 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, and amortization of favorable and unfavorable rate land leases and unfavorable rate O&M contracts is recorded within cost 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 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. An impairment charge is measured as the difference between an asset's carrying amount and its fair value. 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 segment related to an operating project within its Enfinity portfolio due to the bankruptcy of a significant customer. During the years ended December 31, 2016 and 2017, the Company recognized an impairment charge of $15.7 million and $1.4 million, respectively, 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. The Company also recorded a $3.3 million charge within impairment of renewable energy facilities for the year ended December 31, 2016 due to the decision to abandon certain residential construction in progress assets that were not completed by SunEdison as a result of the SunEdison Bankruptcy. Impairment charges are reflected within impairment of renewable energy facilities in the consolidated statements of operations (see Note 4. Acquisitions and Dispositions and Note 5. Renewable Energy Facilities for further discussion).

Goodwill

The Company evaluates goodwill for impairment at least annually on December 1^st. 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.

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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 in Saeta Yield S.A.U. (“Saeta”) of $120.6 million as of December 1, 2018 and concluded that the carrying amount of the reporting unit does not exceed its fair value. No goodwill impairment charges were recorded for the years ended December 31, 2018 and 2017. The Company recorded a goodwill impairment charge of $55.9 million for the year ended December 31, 2016 as reflected in the consolidated statements of operations (see Note 7. Goodwill for further discussion).

Capitalized Interest

Interest incurred on funds borrowed to finance construction of renewable energy facilities is capitalized until the system is ready for its intended use. The amount of interest capitalized during the years ended December 31, 2018 and 2016 was $0.2 million and $1.6 million, respectively. There was no interest capitalized during the year ended December 31, 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 deposit 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 will be 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 over the course of 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 construction 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), with the exception of the costs related to the Company's revolving credit facilities, which are presented as a non-current asset on in the consolidated balance sheets within other assets. As of December 31, 2018 and 2017, the Company had $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 weighted average cost of purchase or net realizable value within prepaid expenses and other current assets in the consolidated balance sheets. Inventory as of December 31, 2018 and 2017, was $7.6 million and $5.7 million, respectively. Spare parts are expensed to cost of operations in the consolidated statements of operations or capitalized to renewable energy facilities, as appropriate, when installed or used.

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Asset Retirement Obligations

Asset retirement obligations are accounted for in accordance with 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 the carrying amount of the related renewable energy facility is correspondingly increased. Over time, the liability is accreted to its expected future value. The corresponding renewable energy facility that is capitalized at inception is depreciated over its useful life.

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 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.

During the fourth quarter of 2018, the Company revised the accretion period related to its wind projects and determined that these obligations should be accreted to expected future value over the remaining useful life of the of the corresponding components of the renewable energy facilities rather than the expected weighted-average life of the assets, consistent with the depreciation expense that is recorded on the asset retirement cost recognized within renewable energy facilities and using its estimate of the future timing of settlement. This change resulted in a $15.7 million reduction in the Company’s asset retirement obligation and corresponding renewable energy facility carrying amount 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, of which $4.4 million of the accretion and depreciation expense reduction related to amounts previously reported for the years ended December 31, 2017, 2016 and 2015. The quarterly accretion and depreciation expense reduction that relates to each of the first three quarters of 2018 was approximately $0.5 million. Management performed an assessment of the balance sheet and income statement impact on its previously issued filings and determined it to be immaterial.

Revenue From Contracts With Customers

Adoption of Topic 606

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which replaces most existing revenue recognition guidance in U.S. GAAP and requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. Additionally, the new standard requires an entity to disclose additional quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies how to apply the implementation guidance on principal versus agent considerations related to the sale of goods or services to a customer as updated by ASU No. 2014-09. The Company adopted these standards as of January 1, 2018, which it collectively refers to as “Topic 606.” The Company analyzed the impact of Topic 606 on its revenue contracts which primarily include bundled energy and incentive sales through PPAs, individual REC sales, and upfront sales of federal & state incentive benefits recorded. The Company elected to apply a modified retrospective approach with a cumulative-effect adjustment to accumulated deficit recognized as of January 1, 2018 for changes to revenue recognition resulting from Topic 606 adoption as described below. The Company adopted Topic 606 for all revenue contracts in scope that had future performance obligations at January 1, 2018, and elected to use the contract modification practical expedient for purposes of computing the cumulative transition adjustment.

The Company accounts for the majority of its PPAs as operating leases under ASC 840, Leases and recognizes rental income as revenue when the electricity is delivered. The Company elected not to early adopt ASC 842, Leases in fiscal 2018. The expected impact of the adoption of the new lease standard is discussed below. For PPAs under the scope of Topic 606 in fiscal 2018, the Company concluded that there were no material changes to revenue recognition patterns from existing accounting practice. See below for the revenue recognition policy of PPAs.

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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 now 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 was 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 17.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 leases is recorded as revenue when the electricity is delivered. The Company adopted ASC 842, Leases on January 1, 2019. The Company 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.

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.

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 type of arrangements, volume reflects total energy generation measured in 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.

For the year ended December 31, 2018, the Company’s energy revenue from PPA contracts with solar and wind customers was $39.6 million and $55.0 million, respectively, which does not include the market energy sales from the regulated solar and wind segment discussed below. As of December 31, 2018, the Company’s receivable balances related to PPA contracts with solar and wind customers was approximately $11.2 million. Trade receivables for PPA contracts are reflected in accounts receivable, net in the consolidated balance sheets. The Company typically receives payment within 30 days for invoiced PPA revenue. The Company does not have any other significant contract asset or liability balances related to PPA revenue.

Energy revenues yet to be earned under these contracts are expected to be recognized between 2019 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.

Regulated Solar and Wind 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 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.

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. Accordingly, the Company applied the practical expedient in Topic 606 and 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

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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. There was no impact related to the adoption of Topic 606 on the amortization of favorable and unfavorable rate revenue contracts. See Note 8. Intangible Assets, Net.

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 now recognized into revenue when delivered and invoiced under Topic 606. This was a change from the Company’s prior year accounting policy which recognized REC sales upon underlying electricity generation. The impact of the adoption resulted in a decrease in operating revenues, net of $3.7 million during the year ended December 31, 2018. Incentive revenues yet to be earned for fixed price incentive contracts are expected to be $61.1 million and recognized between 2019 and 2031. 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. Similar to PPA revenues under Topic 606, the pattern of revenue recognition for these incentive arrangements is recognized over time coinciding with the underlying revenue generation which is consistent with the Company’s policy prior to the adoption of Topic 606. For the year ended December 31, 2018, the Company’s incentive revenue from facility-linked contracts with customers was $28.9 million. Revenue accruals for facility linked incentive contracts within accounts receivable, net were $3.1 million as of December 31, 2018. The Company applied the practical expedient in Topic 606 to its variable consideration incentive contract arrangements where revenues are linked to the underlying generation of the renewable energy facilities, 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.

Deferred Revenue

Deferred revenue primarily consists of upfront incentives or subsidies received from various state governmental jurisdictions for operating certain of the Company's renewable energy facilities. Prior to the adoption of Topic 606, the Company deferred sales of ITCs through its lease pass-through fund arrangements as a deferred revenue liability in the consolidated balance sheets. The Company now recognizes revenue related to the sales of ITCs at the point in time when the related solar energy systems are placed in service. The Company concluded that the likelihood of a recapture event related to these assessments is remote. Under Topic 605, the Company would have recognized an increase of $16.3 million in non-cash deferred revenue within operating revenues, net for the year ended December 31, 2018. The remaining deferred revenue balance in the consolidated balance sheet as of December 31, 2018, consisted of upfront government incentives of $8.8 million and contract liabilities of $4.9 million related to performance obligations that have not yet been satisfied. These contract liabilities represent 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, 2018 related to contract liabilities was $1.3 million.

Prior to the adoption of Topic 606, deferred revenue was recognized on a straight-line basis over the depreciable life of the renewable energy facility or upon the contingency of claw-back of the tax credits resolve as the Company fulfills its obligation to operate these renewable energy facilities. Recognition of deferred revenue was $18.2 million and $16.5 million during the years endedDecember 31, 2017 and 2016, respectively. See Note 3. Revenue 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

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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.

Adoption of ASU 2018-02

In February 2018, the FASB issued ASU No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income to help entities address 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 amendment provides entities with an option to reclassify stranded tax effects within AOCI to retained earnings in each period in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Act (or portion thereof) is recorded. The amendment also includes disclosure requirements regarding the issuer’s accounting policy for releasing income tax effects from AOCI. The optional guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, and entities should apply the provisions of the amendment either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Act is recognized.

During the fourth quarter of 2018, the Company early adopted ASU No. 2018-02 and elected the provisions of the amendment in the period of adoption. 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 (See Note 21. Accumulated Other Comprehensive Income).

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.

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.

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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

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU amends the hedge accounting model to enable entities to better portray the economics of their risk management activities in the financial statements and simplifies the application of hedge accounting in certain situations. ASU No. 2017-12 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018, with early adoption permitted. ASU 2017-12 requires a modified retrospective transition method in which the Company recognizes the cumulative effect of the change on the opening balance of each affected component of equity as of the date of adoption. The Company adopted ASU 2017-12 on March 26, 2018 with the adoption impact reflected on a modified retrospective basis as of January 1, 2018, which resulted in the following primary changes:

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• The ineffective hedging portion of derivatives designated as hedging instruments is no longer required to be measured, recognized or reported. Alternatively, the entire change in the fair value of the designated hedging instrument is recorded in accumulated other comprehensive income (“AOCI”);

• The Company will perform ongoing prospective and retrospective hedge effectiveness assessments qualitatively after performing the initial test of hedge effectiveness on a quantitative basis and only to the extent that an expectation of high effectiveness can be supported on a qualitative basis in subsequent periods;

• For derivatives with periodic cash settlements and a non-zero fair value at hedge inception, the gains or losses recorded in AOCI in a qualifying cash flow hedging relationship are reclassified to earnings on a systematic and rational basis over the hedge term; and

• For derivatives with components excluded from the assessment of hedge effectiveness, the gains or losses recorded in AOCI on such excluded components in a qualifying cash flow hedging relationship are reclassified to earnings on a systematic and rational basis over the hedge term.

The adoption of ASU 2017-12 resulted 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 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 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.

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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. (Gain) loss on foreign currency exchange, net was $(11.0) million, $(6.1) million and $13.0 million during the years endedDecember 31, 2018, 2017 and 2016, respectively, as reported in the consolidated statements of operations.

Business Combinations

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 renewable energy facilities, 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 concessions and 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.

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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, with the exception of 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 the Company's results of operations.

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, 2018, there were no assets held for sale.

Stock-Based Compensation

Stock-based compensation expense for all share-based payment awards to 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 cost 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 $0.6 million, $0.5 million, $0.5 million for the years ended December 31, 2018, 2017 and 2016, 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

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announced a restructuring plan that went into effect upon the closing of the Merger. The Company recognized $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, 2018 and 2017. Severance and transition bonus payments were $5.5 million and $1.0 million during the years ended December 31, 2018 and 2017.

Recently Adopted Accounting Standards - Additional Guidance Adopted in 2018

In addition to the adoption of Topic 606, ASU No. 2017-12 and ASU No. 2018-02 mentioned above, the Company adopted the following standards during the year ended December 31, 2018:

In August 2016, the FASB issued ASU No. 2016-15, Statementsof Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statements of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The adoption of ASU No. 2016-15 is required to be applied retrospectively. The Company adopted ASU No. 2016-15 as of January 1, 2018, which did not result in any material adjustments to the Company’s consolidated statements of cash flows.

In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory. The amendments of ASU No. 2016-16 were issued to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Previous GAAP prohibited the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset had been sold to an outside party which resulted in diversity in practice and increased complexity within financial reporting. The amendments of ASU No. 2016-16 require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and do not require new disclosure requirements. The adoption of ASU No. 2016-16 should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The adoption of ASU No. 2016-16 as of January 1, 2018 did not have an impact on the Company’s consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. The amendment seeks to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. The amendments are required to be applied prospectively on or after the effective dates. Accordingly, the Company’s adoption of ASU No. 2017-01 as of January 1, 2018 did not have an impact on the Company’s historical financial statements. Based on the Company’s evaluation of the new guidance, the Company determined that the acquisition of Saeta on June 12, 2018 qualified to be accounted for as an acquisition of a business and the acquisition of a total of 13 megawatt (“MW”) portfolios of operating solar assets located in California, New Jersey, Massachusetts and Southern Spain in 2018 qualified to be accounted for as acquisitions of assets. See Note 4. Acquisitions and Dispositions for further discussion of the Saeta acquisition.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment. The amendment simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard is effective January 1, 2020, with early adoption permitted, and must be adopted on a prospective basis. The Company adopted this new guidance in connection with its annual goodwill impairment test performed on December 1, 2018.

In February 2017, the FASB issued ASU No. 2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This ASU is meant to clarify the scope of ASC Subtopic 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancial assets. ASU No. 2017-05 is to be

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applied using a full retrospective method or a modified retrospective method as outlined in the guidance. The adoption of ASU No. 2017-05 as of January 1, 2018 did not have an impact on the Company’s consolidated financial statements.

In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. The amendment clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as a modification. The new guidance is expected to reduce diversity in practice and result in fewer changes to the terms of an award being accounted for as a modification. Changes to the terms or conditions of a share-based payment award that do not impact the fair value of the award, vesting conditions and the classification as an equity or liability instrument will not need to be assessed under modification accounting. The amendments in this update should be applied prospectively to an award modified on or after the adoption date. Accordingly, the Company’s adoption of ASU No. 2017-09 as of January 1, 2018 did not have an impact on the Company’s historical financial statements. The Company did not change the terms or conditions of any unvested share-based payment awards outstanding during the year ended December 31, 2018, but will apply the impact of this standard in the future should it change the terms or conditions of any share-based payment awards.

In February 2018, the FASB issued ASU No. 2018-03, Technical Corrections and Improvements to Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. This ASU amends and supersedes various paragraphs that contain SEC guidance in ASC 320, Investments - Debt Securities and ASC 980, Regulated Operations. ASU No. 2018-03 is effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years beginning after June 15, 2018. Public business entities with fiscal years beginning between December 15, 2017 and June 15, 2018 are not required to adopt these amendments until the interim period beginning after June 15, 2018. The adoption of ASU No. 2018-03 as of July 1, 2018 did not have an impact on the Company’s consolidated financial statements.

In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740) – Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118. The ASU added seven paragraphs to ASC 740, Income Taxes, that contain SEC guidance related to the application of U.S. GAAP when preparing an initial accounting of the income tax effects of the Tax Act which, among other things, allows for a measurement period not to exceed one year for companies to finalize the provisional amounts recorded as of December 31, 2017. The ASU was effective upon issuance. See Note 11. Income Taxes and Note 17.Non-Controlling Interests for disclosures on the Company’s accounting for the Tax Act.

Recently Issued Accounting Standards Not Yet Adopted

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which primarily changes the lessee’s accounting for operating leases by requiring recognition of lease right-of-use assets and lease liabilities. 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 the Effective Date Method of adoption.

The Company has made the following elections provided under the standard:

• Package of practical expedients that permits the Company to retain its existing lease assessment and classification;

• Practical expedient that allows the Company to not evaluate existing and expired land easements;

• Practical expedient to not separate non-lease components in power purchase agreement 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 12-months or less from the commencement date.

The Company has 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 Company is continuing the analysis of the contractual arrangements that may qualify as leases under the new standard and expects the most significant impact will be the recognition of the right-of-use assets and lease liabilities for renewable energy facilities. The analysis and evaluation of the new standard will continue through the effective date in the first quarter of 2019. The Company is in the process of implementing a new lease accounting information system to assist with the tracking and accounting for leases. The Company must complete its analysis of contractual arrangements, quantify all impacts of this new guidance, and evaluate related disclosures. The Company must also implement any necessary changes/modifications to processes, accounting systems, and internal controls.

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The Company adopted the guidance as of January 1, 2019, using the transition method that allows the Company to initially apply Topic 842 as of January 1, 2019 and recognize a cumulative-effect adjustment to the opening balance of accumulated deficit in the period of adoption. The Company does not expect to recognize a material adjustment to accumulated deficit upon adoption.

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 is currently evaluating the effect of the new guidance 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 is currently evaluating the effect of the new guidance on its consolidated financial statements.

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 U.S. benchmark interest rates permitted in the application of hedge accounting by adding the SOFR as a permissible U.S. benchmark rate. The new amendments are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the effect of the new guidance on its consolidated financial statements for any future application of hedge accounting involving SOFR as a benchmark interest rate.

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 is currently evaluating the effect of the new guidance on its consolidated financial statements.

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3. REVENUE

As discussed in Note 2. Summary of Significant Accounting Policies, on January 1, 2018, the Company adopted Topic 606. The following tables present revenue disaggregated by segment and major product for the year ended December 31, 2018, and provide a reconciliation of the adoption impact of Topic 606 on the consolidated statements of operations for the year ended December 31, 2018, and consolidated balance sheets as of December 31, 2018. There was no net impact on net cash provided by operating activities in the consolidated statements of cash flows for the year ended December 31, 2018 resulting from the adoption of Topic 606.

Topic 606 Adoption Impact on Consolidated Statements of Operations

	Year Ended December 31, 2018
	As Reported											Adjustments					Amounts excluding Topic 606 Adoption
(In thousands)	Solar			Wind			Regulated Solar and Wind		Total			REC Sales			ITC Sales
PPA rental income	$	198,610		$	192,324		$	—	$	390,934		$	—		$	—	$	390,934
Commodity derivatives	—			46,287			—		46,287			—			—		46,287
PPA and market energy revenue	39,566			54,998			58,742		153,306			—			—		153,306
Capacity revenue from remuneration programs1	—			—			108,242		108,242			—			—		108,242
Amortization of favorable and unfavorable rate revenue contracts, net	(9,743		)	(29,024		)	—		(38,767		)	—			—		(38,767		)
Energy revenue	228,433			264,585			166,984		660,002			—			—		660,002
Incentive revenue	70,533			16,364			19,671		106,568			(3,673		)	16,315		119,210
Operating revenues, net	298,966			280,949			186,655		766,570			(3,673		)	16,315		779,212
Depreciation, accretion and amortization expense									341,837			—			—		341,837
Impairment of renewable energy facilities									15,240			—			—		15,240
Operating costs and expenses									339,514			—			—		339,514
Operating income									69,979			(3,673		)	16,315		82,621
Interest expense, net									249,211			—			—		249,211
Other expenses, net									(13,615		)	—			—		(13,615		)
Loss before income tax expense									(165,617		)	(3,673		)	16,315		(152,975		)
Income tax benefit									(12,290		)	—			—		(12,290		)
Net loss									$	(153,327	)	$	(3,673	)	$	16,315	$	(140,685	)

———

(1) Represents the return related to the Company’s investments associated with its renewable energy facilities in Spain, as discussed in “Regulated solar and wind revenue” in Note 2. Summary of Significant Accounting Policies.

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Topic 606 Adoption Impact on the Consolidated Balance Sheet

	As of December 31, 2018
	As Reported		Adjustments					Amounts excluding Topic 606 Adoption
(In thousands)			REC Sales		ITC Sales
Accounts receivable, net	$	145,161	$	21,603	$	—		$	166,764
Other current assets	356,024		—		—			356,024
Total current assets	501,185		21,603		—			522,788
Non-current assets	8,829,169		—		—			8,829,169
Total assets	$	9,330,354	$	21,603	$	—		$	9,351,957
Deferred revenue	$	1,626	$	—	$	16,310		$	17,936
Other current liabilities	686,656		—		—			686,656
Total current liabilities	688,282		—		16,310			704,592
Deferred revenue, less current portion	12,090		—		8,272			20,362
Other non-current liabilities	5,861,565		—		—			5,861,565
Total liabilities	6,561,937		—		24,582			6,586,519
Redeemable non-controlling interests and total stockholders’ equity	2,768,417		21,603		(24,582		)	2,765,438
Total liabilities, redeemable non-controlling interests and stockholders’ equity	$	9,330,354	$	21,603	$	—		$	9,351,957

4. ACQUISITIONS AND DISPOSITIONS

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 1,028 MW of wind and solar 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 Class A common stock to Orion Holdings and BBHC Orion Holco L.P. as discussed in Note 14. 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.

As discussed in Note 2. Summary of Significant Accounting Policies, the Company accounted for the acquisition of Saeta under the acquisition method of accounting for business combinations. The final accounting for the Saeta acquisition has not been completed because the evaluation necessary to assess the fair values of acquired assets and assumed liabilities is still in process. The preliminary allocation of the acquisition-date fair values of assets, liabilities and redeemable non-controlling interests pertaining to this business combination as of December 31, 2018 and changes from prior quarter were as follows:

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(In thousands)	Saeta as of June 12, 2018 reported at June 30, 2018		Adjustments			Saeta as of June 12, 2018 reported at December 31, 2018
Renewable energy facilities in service	$	1,988,993	$	4,527		$	1,993,520
Accounts receivable	90,555		788			91,343
Intangible assets	992,883		41,293			1,034,176
Goodwill	115,381		7,725			123,106
Other assets	44,190		(788		)	43,402
Total assets acquired	3,232,002		53,545			3,285,547
Accounts payable, accrued expenses and other current liabilities	92,965		67			93,032
Long-term debt, including current portion	1,906,831		—			1,906,831
Deferred income taxes	174,080		(2,707		)	171,373
Asset retirement obligations	11,454		56,252			67,706
Derivative liabilities1	137,002		—			137,002
Other long-term liabilities	23,069		(67		)	23,002
Total liabilities assumed	2,345,401		53,545			2,398,946
Redeemable non-controlling interests2	55,117		—			55,117
Purchase price, net of cash and restricted cash acquired3	$	831,484	$	—		$	831,484

———

(1) Derivative liabilities are included within other liabilities in the consolidated balance sheets.

(2) The fair value of the non-controlling interest 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 is 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 concession and license 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 excess of the purchase price over the estimated fair value of the net assets acquired was recorded as goodwill. As of the date of these financial statements, the analysis of the fair values of renewable energy facilities, intangible assets, asset retirement obligations, long-term debt and deferred income taxes have yet to be completed. The additional information needed by the Company to finalize the measurement of these provisional amounts include the assessment of the estimated removal costs and salvage values of renewable energy facilities, credit spreads of non-recourse project debt and additional information related to the renewable energy tariff system in certain markets. The provisional amounts for this business combination are subject to revision until these evaluations are completed.

The results of operations of Saeta are included in the Company’s consolidated results since the date of acquisition. The operating revenues and net income of Saeta reflected in the consolidated statements of operations for the year ended December 31, 2018 were $221.2 million and $38.2 million, respectively.

Intangibles at 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. The Company attributed intangible asset value to concessions and license agreements 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.

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	Saeta as of June 12, 2018
	Fair Value (In thousands)	Weighted Average Amortization Period (In years)1
Intangible assets - concession and licensing contracts	1,034,176	15 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 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, 2018, 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.

	Year Ended December 31,
(In thousands)	2018			2017
Total operating revenues, net	$	950,992		$	986,081
Net loss	(143,903		)	(210,427		)

Acquisition Costs

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. There were no acquisition costs incurred by the Company for the year ended December 31, 2017. These costs are reflected as acquisition costs and acquisition costs - affiliate (see Note 19. Related Parties) in the consolidated statements of operations and are excluded from the unaudited pro forma net loss amount disclosed above.

U.K. Portfolio Sale

On May 11, 2017, the Company announced that TerraForm Power Operating, LLC (“Terra Operating LLC”) 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. Terra Operating LLC 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 has retained one11.1 MW solar project in the United Kingdom.

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 owns and operates 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 owns and operates 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

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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.

Acquisitions of Renewable Energy Facilities from SunEdison

The following tables summarize the renewable energy facilities acquired by the Company from SunEdison through a series of transactions during the year ended December 31, 2016. There were no renewable energy facilities acquired from SunEdison during the year ended December 31, 2018 and December 31, 2017. As TerraForm Power was a controlled affiliate of SunEdison during 2016, the assets and liabilities transferred to the Company from SunEdison related to interests under common control with SunEdison, and accordingly, were recorded at historical cost. The difference between the cash purchase price and historical cost of the net assets acquired was recorded as a contribution or distribution from SunEdison, as applicable, upon final funding of the acquisition.

			Year Ended December 31, 2016				As of December 31, 2016
Facility Category	Type	Location	Nameplate Capacity (MW)	Number of Sites	Cash Paid1		Cash Due to SunEdison2		Debt Assumed		Debt Transferred3
Distributed Generation	Solar	U.S.	1.2	3	$	2,750	$	—	$	—	$	—
Utility	Solar	U.S.	18.0	1	36,231		—		—		—
Total			19.2	4	$	38,981	$	—	$	—	$	—

————

(1) Represents the total amount paid to SunEdison. Excludes aggregated tax equity partner payments of $1.6 million to SunEdison.

(2) All amounts were paid to SunEdison for these renewable energy facilities as of December 31, 2016.

(3) $16.7 million of construction debt existed for one of the renewable energy facilities as of the acquisition date. This debt was fully repaid by SunEdison during the third quarter of 2016 using cash proceeds paid by the Company to SunEdison for the acquisition of the facility.

5. RENEWABLE ENERGY FACILITIES

Renewable energy facilities, net consists of the following:

	As of December 31,
(In thousands)	2018			2017
Renewable energy facilities in service, at cost	$	7,298,371		$	5,378,462
Less accumulated depreciation - renewable energy facilities	(833,844		)	(578,474		)
Renewable energy facilities in service, net	6,464,527			4,799,988
Construction in progress - renewable energy facilities	5,499			1,937
Total renewable energy facilities, net	$	6,470,026		$	4,801,925

Depreciation expense related to renewable energy facilities was $270.4 million, $212.6 million and $209.2 million for the years endedDecember 31, 2018, 2017 and 2016, respectively.

Construction in progress amounts include capitalized interest costs and amortization of deferred financing costs incurred during the asset's construction period when funds are borrowed to finance construction, which totaled $0.2 million and $1.6 million during the years ended December 31, 2018 and 2016, respectively. There was no capitalization of interest costs or deferred financing cost amortization for the year ended December 31, 2017.

Impairment Charges

The Company reviews long-lived assets that are held and used for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The Company currently has a REC sales agreement with a customer expiring December 31, 2021 that is significant to an operating project within the Enfinity solar distributed generation portfolio, 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 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

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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 endedDecember 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 its remaining 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.

6. ASSET RETIREMENT OBLIGATIONS

The activity on asset retirement obligations for the years endedDecember 31, 2018, 2017 and 2016 was as follows:

	Year Ended December 31,
(In thousands)	2018			2017			2016
Balance as of the beginning of the year	$	154,515		$	148,575		$	215,146
Additional obligations from renewable energy facilities achieving commercial operation	—			—			2,132
Revisions in estimates for current obligations1	—			—			(7,920		)
Adjustment related to change in accretion period2,3	(15,734		)	—			(22,204		)
Assumed through acquisition	68,441			—			136
Accretion expense	6,866			8,578			8,992
Reclassification to non-current liabilities related to assets held for sale	—			—			(39,850		)
Other	843			(3,238		)	—
Currency translation adjustments	(2,274		)	600			(7,857		)
Balance as of the end of the year	$	212,657		$	154,515		$	148,575

————

(1) Effective December 31, 2016, the Company revised its original estimates of the costs and related amount of cash flows for certain of its asset retirement obligations.

(2) During the fourth quarter of 2016, the Company revised the accretion period for its asset retirement obligations from the term of the related PPA agreement to the remaining useful life of the corresponding renewable energy facility, consistent with the period over which depreciation expense is recorded on the corresponding asset retirement cost recognized within renewable energy facilities and with its estimate of the future timing of settlement.

(3) During the fourth quarter of 2018, the Company revised the accretion period related to its wind projects and determined that these obligations should be accreted to expected future value over the remaining useful life of the of the corresponding components of the renewable energy facilities rather than the expected weighted-average life of the assets, consistent with the depreciation expense that is recorded on the asset retirement cost recognized within renewable energy facilities and using its estimate of the future timing of settlement. This change resulted in a $15.7 million reduction in the Company’s asset retirement obligations and corresponding renewable energy facility 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 did not have any assets that were legally restricted for the purpose of settling the Company's asset retirement obligations as of December 31, 2018, 2017 and 2016.

7. GOODWILL

Goodwill as of December 31, 2018 was $120.6 million and represents the excess of the consideration transferred over the fair values of assets acquired and liabilities assumed from Saeta and reflects the future economic benefits arising from other

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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, 2018, 2017 and 2016:

(In thousands)	Goodwill
Balance as of December 31, 2015	$	55,874
Impairment1	(55,874		)
Balance as of December 31, 2016 and 2017	—
Goodwill resulting from the acquisition of Saeta2	115,381
Adjustments during the period2	7,726
Foreign exchange differences	(2,554		)
Balance as of December 31, 2018	$	120,553

———

(1) The goodwill balance as of December 31, 2015 was attributable to an acquisition of solar distributed generation facilities during the year 2014 from Capital Dynamics, which provided the Company with a scalable distributed generation platform. The goodwill existed within the Company's distributed generation reporting unit within the solar reportable segment and was not deductible for federal income tax purposes. The Company performed its annual impairment test of the carrying value of its goodwill as of December 1, 2016 and concluded that the entire balance of was fully impaired. The impairment was driven by a combination of factors, including lack of near-term growth in the operating segment. The impairment test determined there was no implied value of goodwill, which resulted in an impairment charge of $55.9 million as reflected in goodwill impairment within the consolidated statements of operations for the year ended December 31, 2016.

(2) See Note 4. Acquisitions and Dispositions for further details.

8. INTANGIBLE ASSETS, NET

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
Concession and 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 leases	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 O&M contracts	1 year	5,000		(3,802		)	1,198
Unfavorable rate land lease	14 years	1,000		(218		)	782
Total intangible assets, net2		$	64,508	$	(45,625	)	$	18,883

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The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of December 31, 2017:

(In thousands, except weighted average amortization period)	Weighted Average Amortization Period	Gross Carrying Amount		Accumulated Amortization			Net Book Value
Favorable rate revenue contracts	15 years	$	718,639	$	(102,543	)	$	616,096
In-place value of market rate revenue contracts	19 years	521,323		(73,104		)	448,219
Favorable rate land leases	17 years	15,800		(2,329		)	13,471
Total intangible assets, net		$	1,255,762	$	(177,976	)	$	1,077,786
Unfavorable rate revenue contracts	7 years	$	35,086	$	(16,030	)	$	19,056
Unfavorable rate O&M contracts	2 years	5,000		(2,552		)	2,448
Unfavorable rate land lease	15 years	1,000		(162		)	838
Total intangible liabilities, net2		$	41,086	$	(18,744	)	$	22,342

———

(1) See Note 4. Acquisitions and Dispositions for a discussion of the intangible assets related to Saeta.

(2) The Company’s intangible liabilities are classified within other long-term liabilities in the consolidated balance sheets.

Amortization expense related to the concession and licensing contracts acquired from Saeta is reflected in the consolidated statements of operations within depreciation, accretion and amortization expense. During the year ended December 31, 2018 amortization expense related to concession and licensing contracts was $36.4 million.

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 endedDecember 31, 2018, 2017 and 2016, net amortization expense related to favorable and unfavorable rate revenue contracts resulted in a reduction of operating revenues, net of $38.8 million, $39.6 million and $40.2 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 endedDecember 31, 2018, 2017 and 2016, amortization expense related to the in-place value of market rate revenue contracts was $28.2 million, $25.5 million and $25.2 million, respectively.

Amortization expense related to favorable rate land leases is reflected in the consolidated statements of operations within cost of operations. Amortization related to the unfavorable rate land lease and unfavorable rate O&M contracts is reflected in the consolidated statements of operations as a reduction of cost of operations. During the years endedDecember 31, 2018, 2017 and 2016, net amortization related to favorable and unfavorable rate land leases and unfavorable rate O&M contracts resulted in a $0.5 million, $0.5 million and $0.6 million reduction of cost of operations, respectively.

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Over the next five years, the Company expects to recognize annual amortization on its intangibles as follows:

(In thousands)	2019			2020			2021			2022			2023
Concession and licensing contracts	$	71,089		$	71,089		$	71,089		$	71,089		$	71,089
Favorable rate revenue contracts	47,384			43,984			42,251			41,021			40,263
Unfavorable rate revenue contracts	(7,678		)	(2,620		)	(1,379		)	(1,275		)	(948		)
Total net amortization expense recorded to operating revenues, net	$	110,795		$	112,453		$	111,961		$	110,835		$	110,404
In-place value of market rate revenue contracts	$	26,019		$	26,019		$	26,019		$	26,014		$	26,009
Total amortization expense recorded to depreciation, accretion and amortization expense	$	26,019		$	26,019		$	26,019		$	26,014		$	26,009
Favorable rate land leases	$	799		$	799		$	799		$	799		$	799
Unfavorable rate O&M contracts	(1,198		)	—			—			—			—
Unfavorable rate land lease	(56		)	(56		)	(56		)	(56		)	(56		)
Total net amortization recorded to cost of operations	$	(455	)	$	743		$	743		$	743		$	743

9. VARIABLE INTEREST ENTITIES

The Company consolidates VIEs in renewable energy facilities when the Company is the primary beneficiary. 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. As a result of the Company's sale of TerraForm Resi Solar Manager, LLC, a subsidiary of the Company that owned and operated 8.9 MW of residential rooftop solar installations, during the second quarter of 2017, the related assets and liabilities of this variable interest entity were deconsolidated (see Note 4. Acquisitions and Dispositions). No other VIEs were deconsolidated during the years endedDecember 31, 2018 and 2017.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Company's consolidated balance sheets are as follows:

	As of December 31,
(In thousands)	2018		2017
Current assets	$	134,057	$	142,403
Non-current assets	3,909,549		4,155,558
Total assets	$	4,043,606	$	4,297,961
Current liabilities	$	120,790	$	119,021
Non-current liabilities	1,014,789		975,839
Total liabilities	$	1,135,579	$	1,094,860

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.

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10.LONG-TERM DEBT

Long-term debt consists of the following:

	As of December 31,						Interest Type	Interest Rate (%)1
(In thousands, except rates)	2018			2017					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			300,000			Fixed	6.63	Senior notes
Senior Notes due 2028	700,000			700,000			Fixed	5.00	Senior notes
Revolver3	377,000			60,000			Variable	4.69	Revolving loan
Term Loan4	346,500			350,000			Variable	4.52	Term debt
Non-recourse long-term debt:
Permanent financing	3,496,370			1,616,729			Blended5	4.826	Term debt / Senior notes
Financing lease obligations	77,066			115,787			Imputed	5.856	Financing lease obligations
Total principal due for long-term debt and financing lease obligations	5,796,936			3,642,516				4.876
Unamortized discount, net	(15,913		)	(19,027		)
Deferred financing costs, net	(19,178		)	(24,689		)
Less current portion of long-term debt and financing lease obligations	(464,332		)	(403,488		)
Long-term debt and financing lease obligations, less current portion	$	5,297,513		$	3,195,312

———

(1) As of December 31, 2018.

(2) Outstanding corporate-level debt represents debt issued by Terra Operating LLC and guaranteed by Terra LLC and certain subsidiaries of Terra Operating LLC other than non-recourse subsidiaries as defined in the relevant debt agreements (with the exception of certain unencumbered non-recourse subsidiaries).

(3) On February 6, 2018, Terra Operating LLC elected to increase the total borrowing capacity of its Revolver from $450.0 million, available for revolving loans and letters of credit, to $600.0 million. On October 5, 2018, Terra Operating LLC entered into an amendment to reduce the interest rate on the Revolver by 0.75% per annum. The $377.0 million does not include $99.5 million of outstanding project-level letters of credit that have been issued under the Revolver.

(4) On May 11, 2018, the Company entered into an amendment to the Term Loan whereby the interest rate on the Term Loan was reduced by 0.75% per annum.    

(5) Includes fixed rate debt and variable rate debt. As of December 31, 2018, 39% of this balance had a fixed interest rate and the remaining 61% of this balance had a variable interest rate. The Company has 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).

(6) Represents the weighted average interest rate as of December 31, 2018.

Corporate-level Long-term Debt

Term Loan

On November 8, 2017, Terra Operating LLC entered into a 5-year $350.0 million senior secured term loan (the “Term Loan”), which was used to repay outstanding borrowings under the Midco Portfolio Term Loan (as defined and discussed below) 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 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 subsequent to 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 on the Term Loan was reduced by 0.75% per annum. The Company recognized a $1.5 million loss on extinguishment of debt during the

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year ended December 31, 2018 as a result of this amendment representing write offs of certain 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.

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) 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. 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.

Senior Notes

On January 28, 2015, Terra Operating LLC issued $800.0 million of 5.875% senior notes due 2023 at an offering price of 99.214% of the principal amount. Terra Operating LLC used the net proceeds from the offering to fund a portion of the purchase price payable in the First Wind Acquisition. 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, and Terra Operating LLC used the net proceeds from the offering to repay existing borrowings under the Company’s previous revolving credit facility.

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 “Old Senior Notes due 2025”). Terra Operating LLC used the net proceeds from the offering to fund a portion of the purchase price of the acquisition of the wind power plants from affiliates of Invenergy, LLC (“Invenergy Wind”).

During 2016 and 2017, Terra Operating LLC received certain notices of an event of default under the Old Senior Notes due 2023 and the Old Senior Notes due 2025 for failure to comply with its obligation under the respective indentures to timely file certain of the Company's periodic financial statements, but in each case the Company filed the respective financial statements with the SEC within the grace period for delivery that still applied per the respective indentures (which was extended in one case as discussed directly below), and consequently no events of default occurred with respect to these late filings.

On August 30, 2016, the Company announced the successful completion of a consent solicitation from holders of its Old Senior Notes due 2023 and its Old Senior Notes due 2025 to obtain waivers relating to certain reporting covenants (which included an extension of the deadline for filing the Company's 2015 Form 10-K and Form 10-Q for the first quarter of 2016)

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and to effectuate certain amendments under the respective indentures. Terra Operating LLC received consents from the holders of a majority of the aggregate principal amount of each series of the Old Senior Notes outstanding as of the record date and paid a consent fee to each consenting holder of $5.00 for each $1,000 principal amount of such series of the Old Senior Notes for which such holder delivered its consent. Following receipt of the requisite consents, Terra Operating LLC entered into a supplemental indenture for each series of the Old Senior Notes on August 29, 2016. Effective as of September 6, 2016, these indentures respectively permanently increased the interest rate payable on the Old Senior Notes due 2023 from 5.875% per annum to 6.375% per annum and the interest rate payable on the Old Senior Notes due 2025 from 6.125% per annum to 6.625% per annum. In addition, beginning on September 6, 2016 through and including December 6, 2016, special interest accrued on the Old Senior Notes due 2023 and the Old Senior Notes due 2025 at a rate equal to 3.0% per annum, which was payable in the same manner as regular interest payments on the first interest payment date following December 6, 2016.

On August 11, 2017, the Company announced the successful completion of another consent solicitation from holders of its Old Senior Notes due 2023 and its Old Senior Notes due 2025 to obtain a waiver of the requirement to make an offer to repurchase the Old Senior Notes issued under the respective indentures (at 101% of the applicable principal amount, plus accrued and unpaid interest) upon the occurrence of the change of control that would result from the consummation of the Merger. Terra Operating LLC received consents from the holders of a majority of the aggregate principal amount of each series of the Old Senior Notes outstanding as of the record date and paid a consent fee to each consenting holder of $1.25 per $1,000 principal amount of such series of the Old Senior Notes for which such holder delivered its consent. Upon the closing of the Merger, Terra Operating LLC also paid a success fee of $1.25 per $1,000 principal amount of each series of the Old Senior Notes for which such consenting holder delivered its consent.

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 $700.0 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 proceeds to redeem in full its existing Senior Notes due 2023, of which $950.0 million remained outstanding, at a redemption price that included a make-whole premium of $50.7 million, plus accrued and unpaid interest, and to repay $150.0 million of revolving loans outstanding under the Revolver as described above. As a result of the extinguishment of the Company's existing 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 make-whole premium and the write-off of $21.6 million of unamortized deferred financing costs and debt discounts for the Senior Notes due 2023 as of the redemption date.

The Senior Notes due 2023, Senior Notes due 2025 and Senior Notes due 2028 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, the Term Loan 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 and the Term Loan, senior in right of payment to any future subordinated indebtedness of Terra Operating LLC, and effectively subordinated to all borrowings under the Revolver and the Term Loan, 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 prior to their maturity. If Terra Operating LLC elects to redeem the Senior Notes due 2023 prior to October 31, 2022 or the Senior Notes due 2028 prior to July 31, 2027, Terra Operating LLC would be required to pay a make-whole premium as set forth in the applicable indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2023 or the Senior Notes due 2028 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 Terra Operating LLC elects to redeem the Senior Notes due 2025 prior to June 15, 2020, it would be required to pay a make-whole premium as set forth in the indenture. If Terra Operating LLC elects to redeem the Senior Notes due 2025 on or after June 15, 2020 but prior to June 15, 2023, it would be required pay a redemption premium that includes a premium to par adjustment as set forth in the indenture, and if Terra Operating LLC elects to redeem the Senior Notes due 2025 on or after June 15, 2023, it would be required to pay a redemption price equal to100%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.

Sponsor Line Agreement

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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 make 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 will terminate, and all obligations thereunder will 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 million that were used to fund the acquisition of Saeta which were repaid in full as of December 31, 2018. The Company did not make any draws on the Sponsor Line during the year ended December 31, 2017.

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. This includes 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 each series of the Senior Notes, a default of indebtedness that exceeds the greater of $100.0 million or 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.

Saeta Indebtedness

In relation to the acquisition of Saeta, as discussed in Note 4. Acquisitions and Dispositions, the Company assumed total indebtedness of $1.91 billion predominantly comprised of non-recourse project financing from commercial banks secured by Saeta’s solar and wind power plants. As of December 31, 2018 the Company obtained all required change of control consents in respect of this indebtedness. The interest rates applicable to this assumed indebtedness ranged between 1.1% and 5.7% as of December 31, 2018.

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Non-recourse Long-term Debt

Indirect subsidiaries of the Company have incurred long-term non-recourse debt obligations with respect to the renewable energy facilities that those subsidiaries own directly or indirectly. The indebtedness of these subsidiaries is typically secured by the renewable energy facility's assets (mainly the renewable energy facility) 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 to be 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 TerraForm Power, Terra LLC, Terra Operating LLC and the guarantors under the Senior Notes due 2023, the Senior Notes due 2025, the Senior Notes due 2028, the Revolver, the Sponsor Line and the Term Loan.

Non-recourse Portfolio Term Loan

A wholly owned subsidiary of the Company entered into a $500.0 million non-recourse portfolio term loan commitment that was funded on December 15, 2015 (the “Midco Portfolio Term Loan”) and a majority of the proceeds were used to acquire wind power plants from Invenergy Wind. Interest under the term loan accrued at a rate equal to an adjusted Eurodollar rate plus 5.5%, subject to a 1.0% LIBOR floor (or base rate plus 4.5%). The term loan was secured by indirect equity interests in approximately 1,104.3 MW of the Company's renewable energy facilities, consisting of assets acquired from Invenergy Wind and certain other renewable energy facilities acquired from SunEdison, and was to mature on January 15, 2019, to the extent the Company exercised its extension options. The Company exercised the first two extension options in January and July of 2017, respectively.

In June of 2017, the Company agreed to make a $100.0 million prepayment for this loan in connection with obtaining (i) a waiver to extend the 2016 audited project financial statement deadline under the loan agreement and (ii) a waiver of the change of control default that would arise under this loan agreement as a result of the Merger until, in the case of the change of control waiver, the date that is the earlier of three months following the closing of the Merger and March 31, 2018. This prepayment was made using a portion of the proceeds the Company received from the sale of the U.K. Portfolio as discussed in Note 4. Acquisitions and Dispositions. The Company made approximately $68 million of additional prepayments in the second half of 2017 and repaid the remaining principal balance of $300.0 million on November 8, 2017 using borrowings from the Term Loan that was entered into on that date as discussed above. The Company recognized a $3.2 million loss on extinguishment of debt during the year ended December 31, 2017 as a result of these prepayments and final repayment.

United States Project-level Financing

On June 6, 2018, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement, whereby it issued $83.0 million of 4.59% senior notes, secured by approximately 73 MW of utility-scale solar power plants located in Utah, Florida, Nevada and California that are owned by the Company's subsidiary. The proceeds of this financing were used to pay down the Revolver, which was drawn to fund a portion of the purchase price for the acquisition of Saeta. The non-recourse senior notes mature on August 31, 2040 and amortize on a 22-year sculpted amortization schedule.

On September 28, 2018, one of the Company’s subsidiaries entered into a new non-recourse debt financing agreement whereby it issued $78.8 million of 4.64% senior notes, secured by approximately 51 MW of utility-scale and distributed-generation solar power plants located in New York, New Jersey, Massachusetts, North Carolina, Colorado and California that are owned by the Company’s subsidiaries. The majority of the proceeds of this financing were used to repay a portion of the Revolver in October of 2018. The non-recourse senior notes mature on December 31, 2032 and amortize on a 14-year sculpted amortization schedule.

Spain Project-level Financing

On September 28, 2018, one of the Company’s subsidiaries entered into a new non-recourse debt refinancing arrangement whereby it issued approximately €50.0 million of notes secured by 48 MW of utility-scale wind power plants located in Spain. The new notes consist of €30.0 million Tranche A (the equivalent of approximately $35.0 million on the closing date) maturing in 9.5 years and €20.0 million Euro Tranche B (the equivalent of approximately $23.0 million on the

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closing date) maturing in 12.5 years. Tranche A bears interest at a rate per annum equals to six-month Euro Interbank Offered Rate (“Euribor”) plus an applicable margin of 1.70% for the first five years and 1.15% thereafter. Tranche B bears a fixed interest rate of 2.84%. The net proceeds of this refinancing arrangement were used to repay a portion of the outstanding credit facilities. Both tranches amortize on a sculpted amortization schedule. The Company entered into interest rate swap agreements with counterparties to economically hedge greater than 90% of the cash flows associated with the debt, paying a fixed rate of 3.78% for the first five years and 1.15% for the following two years. In return, the counterparties agreed to pay the variable interest payments to the lenders.

Non-recourse Debt Defaults

As of December 31, 2018 and December 31, 2017, the Company reclassified $166.4 million and $239.7 million, respectively, of the Company’s non-recourse long-term indebtedness, net of unamortized deferred financing costs, to current in the consolidated balance sheets due to defaults still remaining as of the respective financial statement issuance date, which primarily consists 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, as the Company believes there is a reasonable likelihood that it will be able to successfully negotiate a waiver with the lenders and/or cure the defaults. The Company 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 a waiver, (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.

Refer to Note 2. Summary of Significant Accounting Policies for discussion of corresponding restricted cash reclassifications to current as a result of these defaults.

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.

Minimum Lease Payments

The aggregate amounts of minimum lease payments on the Company's financing lease obligations are $77.1 million. Contractual obligations for the years 2019 through 2023 and thereafter, are as follows:

(In thousands)	2019		2020		2021		2022		2023		Thereafter		Total
Minimum lease obligations1	$	5,591	$	5,470	$	5,664	$	7,230	$	3,010	$	50,101	$	77,066

———

(1) Represents the minimum lease payment due dates for the Company's financing lease obligations and does not reflect the reclassification of $19.9 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 payments of long-term debt due after December 31, 2018, excluding financing lease obligations and amortization of debt discounts, premiums and deferred financing costs, as stated in the financing agreements, are as follows:

(In thousands)	2019		2020		2021		2022		2023		Thereafter		Total
Maturities of long-term debt1	$	270,889	$	243,511	$	252,001	$	746,872	$	1,218,092	$	2,994,675	$	5,726,040

———

(1) Represents the contractual principal payment due dates for the Company's long-term debt and does not reflect the reclassification of $166.4 million of long-term debt, net of deferred financing costs of $6.2 million, to current as a result of debt defaults under certain of the Company's non-recourse financing arrangements as of December 31, 2018.

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11. INCOME TAXES

The income tax provision/ (benefit) was calculated based on pre-tax book income (loss) between U.S. and foreign operations as follows:

(In thousands)	2018			2017			2016
Pretax income
United States	$	(182,289	)	$	(292,190	)	$	(237,518	)
Foreign	16,672			36,246			(3,495		)
Total Pretax Book Income	$	(165,617	)	$	(255,944	)	$	(241,013	)

The income tax provision consisted of the following:

(In thousands)	Current			Deferred			Total
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	$	270		$	(19,911	)	$	(19,641	)
Tax expense in equity	—			14,081			14,081
Total	$	270		$	(5,830	)	$	(5,560	)
Year ended December 31, 2016
U.S. federal	$	66		$	2,137		$	2,203
State and local	53			(1,109		)	(1,056		)
Foreign	—			1,587			1,587
Total expense (benefit)	$	119		$	2,615		$	2,734
Tax expense in equity	—			406			406
Total	$	119		$	3,021		$	3,140

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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, 2018 and 35% as of December 31, 2017 and 2016, to loss before income taxes, as follows:

	Year Ended December 31,
	2018		2017		2016
Income tax benefit at U.S. federal statutory rate	21.0	%	35.0	%	35.0	%
Increase (reduction) in income taxes:
State income taxes, net of U.S. federal benefit	5.0		4.0		(5.9	)
Foreign operations	(0.5	)	8.7		(1.5	)
Non-controlling interests	(25.9	)	(9.4	)	(15.9	)
Impairment of goodwill	—		—		(6.2	)
Permanent differences	(1.6	)	—		—
Tax Act rate change impact	—		2.0		—
Return to provision	—		2.8		—
Change in valuation allowance	7.8		(34.1	)	(4.7	)
Other	1.6		—		(1.0	)
Effective tax rate	7.4	%	9.0	%	(0.2	)%

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 (“Section 382”).

On December 31, 2018, the Company executed a reorganization of its Capital Dynamics portfolio which resulted in no 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. As a result of this reorganization, TerraForm Power Holdings, Inc. (formerly known as TerraForm CD Holdings Corporation) will elect to become part of the consolidated US federal and state tax filing group under TerraForm Power for the year ending December 31, 2019. The Company recognized a 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 carryforwards.

For the years ended December 31, 2018 and December 31, 2017, the overall effective tax rate was different than the statutory rate of 21% and 35%, respectively, and was 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, 2016, 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 impairment of nondeductible goodwill and the effects of state income taxes.

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The tax effects of the major items recorded as deferred tax assets and liabilities were as follows:

	As of December 31,
(In thousands)	2018			2017
Deferred tax assets:
Net operating losses and tax credit carryforwards	$	587,833		$	498,245
Derivative liabilities1	33,261			—
Interest expense limitation carryforward	67,887			—
Total deferred tax assets	688,981			498,245
Valuation allowance	(386,336		)	(383,710		)
Net deferred tax assets	302,645			114,535
Deferred tax liabilities:
Investment in partnership	221,693			103,322
Renewable energy facilities	30,261			29,541
Deferred revenue	—			13
Intangible assets1	229,363			—
Other	176			6,632
Total deferred tax liabilities	481,493			139,508
Net deferred tax liabilities	$	178,848		$	24,973

———

(1) Represents recorded deferred income taxes related to the acquisition of Saeta, as discussed in Note 4. Acquisitions and Dispositions.

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, 2018, the Company has gross net operating loss carryforwards of $2.1 billion in the U.S. and gross net operating loss carryforwards of $133.0 million in foreign jurisdictions that will both expire in tax years beginning in 2035. Of the $2.1 billion of gross net operating loss carryforwards generated in the U.S., approximately $600.0 million are limited and are expected to expire unused. For the remaining $1.5 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 net operating loss carryforward period with the exception of certain net operating losses at its Canadian, Portuguese, Spanish and Uruguay operations. The current year movement in the valuation allowance is related to current year activity.

During 2018, the Company identified adjustments related to the outside basis in its investment in partnership at Terra, LLC that impact prior periods. These adjustments created depreciable step-ups for Federal income tax purposes. Therefore, the Company has increased the tax effected NOL deferred tax asset by $96.1 million, decreased the deferred tax liability for its investment in partnership by $135.5 million and increased the related valuation allowance by $231.6 million for the year ended December 31, 2017. These adjustments had no impact to the reported consolidated balance sheets, statements of operations, stockholders’ equity or cash flows. The Company’s management assessed the impact of these adjustments and concluded the impact on the prior period consolidated financial statements was immaterial to each of the affected reporting periods and therefore amendment of previously filed reports was not required. However, management elected to correct the 2017 footnote presentation to reflect the adjustments in the 2017 period.

Prior to the acquisition of Saeta, the Company’s foreign entities had cumulative negative earnings & profits (“E&P”) and therefore 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 is not asserting indefinite reinvestment related to undistributed earnings of its foreign subsidiaries. The Company determined there was no material deferred tax liabilities that needed to be recognized as of December 31, 2018.

In December 2017, the U.S. Securities and Exchange Commission released Staff Accounting Bulletin (“SAB”) 118, which allowed for a measurement period up to one year after the enactment date of the Tax Act to finalize related income tax impacts directly related to the Tax Act. SAB 118 summarized a three-step process to be applied at each reporting period to account for and

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qualitatively disclose: (1) the effects of the change in tax law for which accounting is complete; (2) provisional amounts for the effects of the tax law where accounting is not complete, but that a reasonable estimate can be determined; and (3) a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the Tax Act. The Company has completed the related accounting for the Tax Act in the current period.

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, 2018, 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 proposed regulations during 2018. The Company expects further guidance to be issued in 2019 which may impact the Company’s interpretation of the 2017 Tax Act. The Company will continue to monitor developments as they occur.

As of December 31, 2018 and 2017, respectively, the Company had not identified any uncertain tax positions for which a liability was required under ASC 740-10. The Company expects to complete its analysis on historical tax positions related to the Saeta acquisition within the measurement period.

12. DERIVATIVES

As part of the Company’s risk management strategy, the Company has entered into derivative instruments which include interest rate swaps, foreign currency contracts and commodity contracts to mitigate interest rate, foreign currency and commodity price exposure, respectively. 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 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.

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As of December 31, 2018 and 2017, 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, 2018
Prepaid expenses and other current assets	$	1,478	$	605	$	18	$	—	$	3,344	$	9,783	$	15,228	$	(857	)	$	14,371
Other assets	5,818		2,060		42,530		—		647		40,137		91,192		(344		)	90,848
Total assets	$	7,296	$	2,665	$	42,548	$	—	$	3,991	$	49,920	$	106,420	$	(1,201	)	$	105,219
Other current liabilities	$	465	$	—	$	—	$	34,261	$	1,684	$	—	$	36,410	$	(857	)	$	35,553
Other liabilities	3,334		1,437		—		88,034		1,387		—		94,192		(344		)	93,848
Total liabilities	$	3,799	$	1,437	$	—	$	122,295	$	3,071	$	—	$	130,602	$	(1,201	)	$	129,401
As of December 31, 2017
Prepaid expenses and other current assets	$	—	$	—	$	8,961	$	—	$	63	$	12,609	$	21,633	$	(63	)	$	21,570
Other assets	4,686		—		71,307		—		—		14,787		90,780		—			90,780
Total assets	$	4,686	$	—	$	80,268	$	—	$	63	$	27,396	$	112,413	$	(63	)	$	112,350
Other current liabilities	$	2,490	$	—	$	—	$	197	$	99	$	—	$	2,786	$	(63	)	$	2,723
Other liabilities	4,796		—		—		404		—		—		5,200		—			5,200
Total liabilities	$	7,286	$	—	$	—	$	601	$	99	$	—	$	7,986	$	(63	)	$	7,923

———

(1) Fair value amounts are shown before the effects of counterparty netting adjustments.

(2) Represents netting of derivative exposures covered by qualifying master netting arrangements.

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As of December 31, 2018 and December 31, 2017, 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, 2018 and December 31, 2017 related to the Company’s derivative transactions.

As of December 31, 2018 and 2017, notional amounts for derivative instruments consisted of the following:

	Notional Amount as of December 31,
(In thousands)	2018	2017
Derivatives designated as hedging instruments:
Cash flow hedges:
Interest rate swaps (USD)	357,797	395,986
Interest rate swaps (CAD)	147,522	156,367
Commodity contracts (MWhs)	6,030	15,579
Net investment hedges:
Foreign currency contracts (CAD)	81,600	—
Foreign currency contracts (EUR)	320,000	—
Derivatives not designated as hedging instruments:
Interest rate swaps (USD)	12,326	13,520
Interest rate swaps (EUR)1	1,044,253	—
Foreign currency contracts (EUR)2	640,200	—
Foreign currency contracts (CAD)	—	9,875
Commodity contracts (MWhs)	8,707	987

————

(1) Represents the notional amount of the interest rate swaps acquired from 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 December 31, 2018.

(2) Represents the notional amount of foreign exchange 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, 2018.

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 ISDA Master Agreements with its counterparties. An ISDA Master Agreement is an agreement governing 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, 2018 or 2017 as each of the commodity contracts were in a gain position.

Gains and losses on derivatives not designated as hedging instruments for the years endedDecember 31, 2018, 2017 and 2016 consisted of the following:

	Location of Loss (Gain) in the Statements of Operations	Year Ended December 31,
(In thousands)		2018			2017			2016
Interest rate swaps	Interest expense, net	$	2,565		$	3,161		$	26,280
Foreign currency contracts	(Gain) loss on foreign currency exchange, net	(34,714		)	966			(1,325		)
Commodity contracts	Operating revenues, net	3,209			(5,117		)	(10,890		)

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

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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, 2018 was $38.6 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 4. Acquisitions and Dispositions, 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.

During the second quarter of 2016, the Company discontinued hedge accounting for interest rate swaps that were previously designated as cash flow hedges of the forecasted interest payments pertaining to variable rate project debt in the U.K. Portfolio. Hedge accounting was prospectively discontinued for interest payments occurring before the anticipated sale date of June 2017, and for periods beyond that, the losses of $16.9 million in AOCI were fully reclassified into interest expense, net during the second quarter of 2016. Subsequent to the discontinuation of hedge accounting, the Company recognized additional net unrealized losses of $7.3 million pertaining to these interest rate swaps during the year ended December 31, 2016 that are also reported in interest expense, net in the consolidated statements of operations.

Gains and losses recognized related to interest rate swaps, foreign currency forward contracts and commodity derivative contracts designated as hedging instruments for the years endedDecember 31, 2018, 2017 and 2016 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)	2018			2017			2016			2018		2017		2016
Interest rate swaps	$	1,034		$	(396	)	$	(20,360	)	$	—	$	—	$	—
Foreign currency contracts	11,169			—			—			—		—		—
Commodity derivative contracts	(3,163		)	18,008			20,274			452		—		—
Total	$	9,040		$	17,612		$	(86	)	$	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
	2018			2017			2016			2018		2017			2016
Interest expense, net	$	1,307		$	5,507		$	11,618		$	—	$	(1,270	)	$	—
Gain on foreign currency exchange, net	—			—			—			—		—			—
Operating revenues, net	(1,804		)	(7,754		)	(12,572		)	—		(2,923		)	5,121
Total	$	(497	)	$	(2,247	)	$	(954	)	$	—	$	(4,193	)	$	5,121

———

(1) Net of tax expense of $3.6 million and a benefit of $0.1 million attributed to interest rate swaps during the year ended December 31, 2018 and 2017, respectively. There were no taxes attributed to interest rate swaps during the year ended December 31, 2016. Net of tax expense of $3.9 million 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, 2017 and 2016. Net of tax benefit of $2.0 million and tax expense of $2.5 million and $0.4 million attributed to commodity contracts during the years ended December 31, 2018, 2017 and 2016, respectively.

(2) Net of tax expense of $0.3 million for the year ended December 31, 2018.

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(3) 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. There were no taxes attributed to interest rate swaps during the year ended December 31, 2016. 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. There were no taxes attributed to commodity contracts during the year ended December 31, 2016.

As discussed in Note 2. Summary of Significant Accounting Policies, the Company adopted ASU No. 2017-12 as of January 1, 2018 and recognized a cumulative-effect adjustment of $4.2 million, net of tax of $1.6 million, representing a decrease in beginning 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.

Derivatives Designated as Hedging Instruments

Interest Rate Swaps

The Company has interest rate swap agreements to hedge variable rate non-recoursedebt. These interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. Under the interest rate swap agreements, therenewable energy facilitiespay a fixed rate and the counterparties to the agreements pay a variable interest rate. The amounts deferred in AOCI and reclassified into earnings during theyears endedDecember 31, 2018,2017and2016related to these interest rate swaps are provided in the tables above.The gain expected to be reclassified into earnings over the next twelve months is approximately $2.5 million. The maximum term of outstanding interest rate swaps designated as hedging instruments is 15 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 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. 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, 2018, the total notional amount of foreign currency forward contracts designated as net investment hedges was €320.0 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 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 reported in AOCI and subsequently reclassified to earnings in the periods when the hedged transactions affect earnings. The amounts deferred in AOCI and reclassified into earnings during theyears endedDecember 31, 2018,2017and2016related 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 $2.0 million. The maximum term of the outstanding commodity contract designated as a hedging instrument is 9 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

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for under hedge accounting.

Foreign Currency Contracts

The Company has foreign currency contracts in order to economically hedge its exposure to foreign currency fluctuations. The settlement of these hedges occurs on a quarterly basis through maturity. As these derivatives are not accounted for under hedge accounting, the changes in fair value are recorded in (gain) loss on foreign currency exchange, net in the consolidated statements of operations.

Commodity Contracts

The Company has commodity contracts in order 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 extrapolation from or interpolation between actively traded contracts, as well as 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 fair value 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 and, to a lesser degree, credit spreads and volatilities. 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, 2018								As of December 31, 2017
(In thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Interest rate swaps	$	—	$	7,296	$	—	$	7,296	$	—	$	4,686	$	—	$	4,686
Commodity contracts	—		12,816		79,652		92,468		—		27,396		80,268		107,664
Foreign currency contracts	—		5,455		—		5,455		—		—		—		—
Total derivative assets	$	—	$	25,567	$	79,652	$	105,219	$	—	$	32,082	$	80,268	$	112,350
Liabilities
Interest rate swaps	$	—	$	126,094	$	—	$	126,094	$	—	$	7,887	$	—	$	7,887
Foreign currency contracts	—		3,307		—		3,307		—		36		—		36
Total derivative liabilities	$	—	$	129,401	$	—	$	129,401	$	—	$	7,923	$	—	$	7,923

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The Company's interest rate swaps, foreign currency contracts and certain commodity contracts not designated as hedging instruments are considered Level 2, since all significant inputs are corroborated by market observable data. The Company's commodity contract designated as hedging instruments and the commodity contract that disqualified for hedge accounting during the year ended December 31, 2018 (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, 2018 and 2017.

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 endedDecember 31, 2018 and 2017:

	Year Ended December 31,
(In thousands)	2018			2017
Beginning balance	$	80,268		$	66,138
Realized and unrealized gains (losses):
Included in other comprehensive (loss) income	(4,736		)	11,207
Included in operating revenues, net	6,244			12,205
Settlements	(2,124		)	(9,282		)
Balance as of December 31	$	79,652		$	80,268

The significant unobservable inputs used in the valuation of the Company’s commodity contracts categorized as Level 3 in the fair value hierarchy as of December 31, 2018 are as follows:

(In thousands, except range)	Fair Value as of December 31, 2018
Transaction Type	Assets		Liabilities		Valuation Technique	Unobservable Inputs as of December 31, 2018
Commodity contracts - power	$	79,652	$	—	Option model	Volatilities	14.8%
							Range
					Discounted cash flow	Forward price (per MWh)	$	9.46	$	164.08

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.

Fair Value of Debt

The carrying amount and estimated fair value of the Company's long-term debt as of December 31, 2018 and 2017 was as follows:

	As of December 31, 2018				As of December 31, 2017
(In thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	5,761,845	$	5,789,702	$	3,598,800	$	3,702,470

The fair value of the Company's long-term debt, except the corporate-level senior notes was determined using inputs

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classified as Level 2 and a discounted cash flow approach using market rates for similar debt instruments. The fair value of the 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 value of the Senior Notes due 2023, Senior Notes due 2025 and Senior Notes due 2028 were 93.47%, 89.78% and 102.50% of face value as of December 31, 2018, respectively. The fair value of the Senior Notes due 2023, Senior Notes due 2025 and Senior Notes due 2028 were 99.50%, 109.50% and 99.38% of face value as of December 31, 2017, 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 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 Note5.Renewable Energy Facilities and Note 7. Goodwill.

14. STOCKHOLDERS' EQUITY

Reduction in SunEdison’s Ownership of Class B Shares

On January 22, 2016, TerraForm Power issued 12,161,844 shares of Class A common stock to affiliates of the D.E. Shaw group, Madison Dearborn Capital Partners IV, L.P. and Northwestern University, and Terra LLC issued 12,161,844 Class A units of Terra LLC to TerraForm Power upon conversion of 12,161,844 Class B shares of TerraForm Power common stock and 12,161,844 Class B units of Terra LLC held by SunEdison. After giving effect to the conversion, SunEdison indirectly owned 48,202,310 Class B shares of TerraForm Power and 48,202,310 Class B units of Terra LLC.

Stockholder Protection Rights Agreement

On July 24, 2016, the Company's Board of Directors (the “Board”) adopted a Stockholder Protection Rights Agreement (the “Rights Agreement”) and declared a dividend of one right on each outstanding share of TerraForm Power Class A common stock. The record date to determine which stockholders were entitled to receive the rights was August 4, 2016. The Rights Agreement was adopted in response to the potential sale of a significant equity stake in the Company by SunEdison and the potential accumulation of TerraForm Power Class A shares. The Rights Agreement and the rights expired in accordance with their terms on August 10, 2017, which was the date of the annual stockholders meeting for 2017 of TerraForm Power.

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

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discussed below). As a result of the Merger closing, TerraForm Power is no longer a controlled affiliate of SunEdison, Inc. and is now a controlled affiliate of Brookfield.

At the effective time of the Merger, each share of Class A common stock of TerraForm Power issued and outstanding immediately prior to the effective time of the Merger, with the exception of 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 Class A 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, Inc., SunEdison Holdings Corporation (“SHC”) and SUNE ML 1, LLC (“SML1”). The SunEdison Registration Rights Agreement governed the rights of SunEdison, Inc., 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, the Company's certificate of incorporation was amended and restated. TerraForm Power now has 100,000,000 authorized shares of preferred stock, par value $0.01 per share, and 1,200,000,000 authorized shares of Class A common stock, 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.

Issuance of Class A Common Stock to Affiliates

On June 11, 2018, TerraForm Power entered into a Class A Common Stock Purchase Agreement (“Share Purchase Agreement”) with Orion Holdings and BBHC Orion Holdco L.P. (collectively, the “Purchasers”), both affiliates of Brookfield. Pursuant to the Share Purchase Agreement, the Purchasers purchased in a private placement a total of 60,975,609 shares of TerraForm Power’s Class A common stock for a price per share of $10.66, representing total consideration of approximately $650.0 million. No underwriting discounts or commissions were paid with respect to this private placement. These newly issued shares of TerraForm Power were not registered with the SEC in reliance on Section 4(a)(2) of the Securities Act and the acknowledgment of each of the 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. As a result of this private placement, affiliates of Brookfield now hold approximately 65% of TerraForm Power’s Class A common stock.

The proceeds of the offering 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 Class A shares by the Purchasers was made pursuant to 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.

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Issuance of Shares upon Final Resolution of Chamblee Class Action

On August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Class A 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.

Dividends

The following table presents cash dividends declared and/or paid on Class A common stock during the years ended December 31, 2018 and 2017. The Company did not declare or pay any dividends during the year ended December 31, 2016.

	Type	Dividends per Share		Declaration Date	Record Date	Payment Date
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 dividend (the “Special Dividend”) 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 31, 2018, the Board of Directors of the Company authorized a program to repurchase up to 5% of the Company’s Class A common stock outstanding as of July 31, 2018, through July 31, 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 shares. Any repurchased common stock will be held by the Company as treasury shares. The Company expects to fund any repurchases from available liquidity.

As of December 31, 2018, no shares were repurchased under the program.

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15. 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, 2018, an aggregate of 3,822,821 shares of Class A 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 and $3.4 million for the years ended December 31, 2017 and 2016, respectively, 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 years ended December 31, 2017 and 2016, 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, Inc. 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, Inc. and TerraForm Global that was allocated to the Company was $5.5 million and $2.7 million for the years ended December 31, 2017 and 2016, respectively, 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, Inc. would be canceled. As a result, all previously unrecognized compensation cost pertaining to unvested equity awards in the stock of SunEdison, Inc. 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 Class A common stock held by the terminated participant will be forfeited. All unvested RSAs are paid dividends 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, 2018 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 and 2018	—		$	—	$	—

The total fair value of RSAs that vested during the years ended December 31, 2017 and 2016 was $4.3 million and $5.8 million, respectively. No RSAs were granted during those periods. As of December 31, 2018, there was no unrecognized compensation cost in relation to RSAs.

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Restricted Stock Units

RSUs will not entitle the holders to voting rights and holders of the RSUs will not have any right to receive dividends or distributions. The following table presents information regarding outstanding RSUs as of December 31, 2018 and 2017 and changes during the year then ended:

	Number of RSUs Outstanding		Aggregate Intrinsic Value (in millions)		Weighted Average Remaining Contractual Life (In Years)
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		$	0.2	—

The total fair value of RSUs that vested during the years ended December 31, 2017 and 2016 was $16.7 million and $5.6 million, respectively. The weighted average fair value of RSUs on the date of grant during the same periods was $12.22 and $11.61, 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, 2018 was $0.9 million. The vesting schedule of the RSUs awarded in 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 Note1.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 years ended December 31, 2017 and 2016, the Company awarded 523,877 and 439,595 time-based RSUs, respectively, 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 and $5.1 million, respectively, which was calculated based on the Company's closing stock price on the respective dates of grant. The vesting schedules 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. During the year ended December 31, 2018, the Company did not award any time-based RSUs.

Performance-based RSUs

On July 28, 2015, SunEdison began recognizing expense related to 199,239 performance-based RSUs granted by the Company to certain employees of First Wind in connection with its acquisition by SunEdison on January 29, 2015. The performance-based awards were issued in three tranches covering the 2015, 2016 and 2017 fiscal year performance periods and were based on the achievement of targets related to additions to SunEdison's renewable energy generation project development pipeline and backlog, the volume of renewable energy generation projects transferred into the Company or SunEdison's warehouse vehicles and the achievement of cash available for distribution by wind power plants sold to the Company through the First Wind Acquisition agreement. The grant-date fair value of these awards was $6.2 million which was being recognized

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as compensation expense on a straight-line basis over the requisite service periods of one year for the 2015 tranche, two years for the 2016 tranche, and three years for the 2017 tranche. The grant-date fair value of these awards was calculated based on the Company's stock price on the date of grant since meeting the requisite performance conditions was considered probable as of that date. As the achievement of these performance metrics was not considered probable as of the first quarter of 2016, all previously recognized compensation expense for the tranches covering 2015 and 2016 was reversed during the first quarter of 2016. These performance-based RSUs were all forfeited prior to the consummation of the Merger.

Stock Options

As of December 31, 2018 and 2017, there were no outstanding stock options and no unrecognized compensation cost in relation to stock options.

16. EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share is computed by dividing net income (loss) attributable to Class A common stockholders by the number of weighted average ordinary shares outstanding during the period. Diluted earnings (loss) per share is computed by adjusting basic income (loss) per share for the impact of weighted average dilutive common equivalent shares outstanding during the period, unless the impact is anti-dilutive. Common equivalent shares represent the incremental shares issuable for unvested restricted Class A common stock.

Unvested RSAs that contain non-forfeitable rights to dividends are treated as participating securities and are included in the earnings (loss) 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 dividends 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 earnings (loss) per share is also adjusted by the amount of deemed dividends 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 income (loss) attributable to Class A common stockholders.

Basic and diluted earnings (loss) per share of the Company's Class A common stock for the years endedDecember 31, 2018, 2017 and 2016 was calculated as follows:

	Year Ended December 31,
(In thousands, except per share amounts)	2018		2017			2016
Basic and diluted (loss) earnings per share:
Net income (loss) attributable to Class A common stockholders	$	12,380	$	(160,154	)	$	(123,511	)
Less: accretion of redeemable non-controlling interest	—		(6,729		)	(3,962		)
Less: dividends paid on Class A shares and participating RSAs	—		(285,497		)	—
Undistributed income (loss) attributable to Class A shares	$	12,380	$	(452,380	)	$	(127,473	)
Weighted average basic and diluted Class A shares outstanding1	182,239		103,866			90,815
Distributed earnings per share	$	—	$	2.75		$	—
Undistributed earnings (loss) per share	0.07		(4.36		)	(1.40		)
Basic and diluted earnings (loss) per share	$	0.07	$	(1.61	)	$	(1.40	)

———

(1) The computation of diluted loss per share of the Company's Class A common stock for the year ended December 31, 2018 excludes the impact of potentially dilutive unvested RSAs and RSUs outstanding during the year as the effect would have been anti-dilutive. As of December 31, 2017, there were no potentially dilutive unvested securities. The computation for diluted loss per share of the Company's Class A common stock for the year ended December 31, 2016 excludes 459,800 of potentially dilutive unvested RSAs and 1,622,953 of potentially dilutive unvested RSUs because the effect would have been anti-dilutive.

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17. 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.

During the second quarter of 2018, the Company discovered certain errors in its unaudited consolidated condensed financial statements for the periods ended March 31, 2018 and 2017, September 30, 2017, and June 30, 2017, and in its annual audited consolidated financial statements for the years ended December 31, 2017, 2016 and 2015. These errors relate to the Company’s accounting for certain intercompany transactions with non-wholly owned controlled subsidiaries and resulted in overstatements of the allocation of net income attributable to the redeemable non-controlling interests with corresponding understatements of the allocation of net income attributable to Class A common stockholders and non-controlling interests. The Company’s management assessed the impact of these adjustments and concluded the impact on the prior period financial statements was immaterial to each of the affected reporting periods and therefore amendment of previously filed reports was not required. However, the correction of the cumulative amount of the prior period errors would have been material to the current year consolidated financial statements and therefore, the Company corrected these errors in the prior periods included herein. These errors occurred between July 1, 2015, and March 31, 2018, therefore, there is no cumulative effect on the Company’s consolidated financial statements as of January 1, 2015. The correction had no impact on the previously reported amounts of consolidated cash flows from operating, investing or financing activities. The prior periods’ amounts related to the corrected balances have been revised as disclosed in the Company’s Quarterly Reports on Form 10-Q for each of the quarters ended June 30, 2018 and September 30, 2018, with sufficient information describing the nature of the changes that were made to the historical consolidated condensed financial statements.

The tables below summarize the effect of the corrections of the previously reported annual consolidated financial statement line items:

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Consolidated Balance Sheet	December 31, 2017
(In thousands)	As Previously Reported			Adjustment			Revised
Deferred income taxes	$	18,636		$	6,336		$	24,972
Total liabilities	3,958,313			6,336			3,964,649
Redeemable non-controlling interests	58,340			(23,680		)	34,660
Additional paid-in capital	1,866,206			5,919			1,872,125
Accumulated deficit	(398,629		)	11,425			(387,204		)
Total TerraForm Power, Inc. stockholders’ equity	1,510,369			17,344			1,527,713
Total stockholders’ equity	2,370,368			17,344			2,387,712

Consolidated Balance Sheet	December 31, 2016
(In thousands)	As Previously Reported			Adjustment			Revised
Deferred income taxes	$	27,723		$	2,897		$	30,620
Total liabilities	4,807,499			2,897			4,810,396
Redeemable non-controlling interests	180,367			(14,392		)	165,975
Accumulated deficit	(234,440		)	7,390			(227,050		)
Total TerraForm Power, Inc. stockholders’ equity	1,252,957			7,390			1,260,347
Non-controlling interests	1,465,042			4,105			1,469,147
Total stockholders’ equity	2,717,999			11,495			2,729,494

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Consolidated Statements of Operations and Comprehensive (Loss) Income	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2016									Twelve Months Ended December 31, 2017
(In thousands, except per share amounts)	As Previously Reported			Adjustment			Revised			As Previously Reported			Adjustment			Revised			As Previously Reported			Adjustment			Revised
Income tax (benefit) expense	$	(13,241	)	$	657		$	(12,584	)	$	494		$	2,240		$	2,734		$	(23,080	)	$	3,439		$	(19,641	)
Net loss	(208,135		)	(657		)	(208,792		)	(241,507		)	(2,240		)	(243,747		)	(232,864		)	(3,439		)	(236,303		)
Net loss subsequent to IPO and excluding pre-acquisition net loss of renewable energy facilities acquired from SunEdison	(209,745		)	(657		)	(210,402		)	(241,507		)	(2,240		)	(243,747		)	(232,864		)	(3,439		)	(236,303		)
Net income attributable to redeemable non-controlling interests	8,512			(2,509		)	6,003			18,365			(11,883		)	6,482			10,884			(9,288		)	1,596
Net loss attributable to non-controlling interest	(138,371		)	798			(137,573		)	(130,025		)	3,307			(126,718		)	(79,559		)	1,814			(77,745		)
Net loss attributable to Class A common stockholders	(79,886		)	1,054			(78,832		)	(129,847		)	6,336			(123,511		)	(164,189		)	4,035			(160,154		)
Loss per share of Class A common stock - Basic and diluted	(1.25		)	0.01			(1.24		)	(1.47		)	0.07			(1.40		)	(1.65		)	0.04			(1.61		)
Total comprehensive loss	(195,005		)	(657		)	(195,662		)	(240,665		)	(2,240		)	(242,905		)	(192,458		)	(3,439		)	(195,897		)
Comprehensive loss subsequent to IPO and excluding pre-acquisition comprehensive income (loss) of renewable energy facilities acquired from SunEdison	(236,631		)	(657		)	(237,288		)	(240,665		)	(2,240		)	(242,905		)	—			—			—
Comprehensive loss attributable to non-controlling interests	(141,266		)	(1,711		)	(142,977		)	(110,830		)	(8,576		)	(119,406		)	(54,018		)	(7,474		)	(61,492		)
Comprehensive loss attributable to Class A common stockholders	(95,365		)	1,054			(94,311		)	(129,835		)	6,336			(123,499		)	$	(138,440	)	$	4,035		$	(134,405	)

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The following table presents the activity of the redeemable non-controlling interests balance for the years ended December 31, 2018, 2017 and 2016:

(In thousands)	Redeemable Non-controlling Interests
Balance as of December 31, 2015	$	173,202
Sale of membership interests and contributions	1,011
Distributions	(10,764		)
Repurchase of redeemable non-controlling interest in renewable energy facility	(7,918		)
Accretion	3,962
Net income	6,482
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

———

(1) The Company recorded a $6.7 million and $4.0 million adjustment during the years ended December 31, 2017 and 2016, respectively, to the value of the Invenergy Wind redeemable non-controlling interest, reflecting the excess of the future redemption value over its carrying amount based on 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.

18.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 relevant 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, 2018, the Company had outstanding letters of credit under the Revolver of $99.5 million and outstanding project-level letters of credit of $197.7 million compared to $102.6 million and $147.0 million as of December 31, 2017, respectively.

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Guarantee Agreements

The Company and its subsidiaries have provided guarantees to certain of its institutional tax equity investors and financing parties in connection with its tax equity financing transactions. These guarantees 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 believes that the likelihood of a significant recapture event of the tax credits is remote and accordingly has not recorded any liability in the consolidated financial statements for any potential recapture obligation.

The Company and its subsidiaries have also provided guarantees in connection with acquisitions of third party assets or to support project contractual obligations, including renewable energy credit sales agreements. The Company and its subsidiaries have also provided other capped or limited contingent guarantees and other support obligations with respect to certain project-level indebtedness.

Commitments to Acquire Renewable Energy Facilities

As of December 31, 2018, the Company had a commitment of $3.4 million to acquire renewable energy facilities.

Operating Leases

The Company leases land and buildings under operating leases. Total rental expense was $21.2 million, $21.0 million and $23.5 million during the years ended December 31, 2018, 2017 and 2016, respectively. 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

Long-Term Service Agreement

On August 10, 2018, the Company executed an 11-year framework agreement with an affiliate of General Electric that, among other things, provides for the roll out, subject to receipt of third party consents, of project level, long-term service agreements (collectively, the “LTSA”) for turbine operations and maintenance, as well as other balance of plant services across the Company’s 1.6 GW North American wind fleet. The Company is in the process of obtaining third party consents for the roll out of the LTSA, which may include the early termination of certain of the Company’s existing service contracts.

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, TerraForm Power and 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. The defendants filed a motion to dismiss the amended complaint on July 5, 2016, on the ground that, among other things,

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SunEdison is a necessary party to this action. The plaintiffs filed an opposition to the motion to dismiss on August 22, 2016. The Company filed its reply on September 12, 2016. A hearing on the motion to dismiss took place on January 24, 2017. On February 6, 2018, the court denied the Company’s motion to dismiss. In January 2019, a pre-trial schedule was agreed between Terra LLC and the plaintiffs and approved by the Court that provided for fact discovery and depositions. The Company cannot predict the impact on this litigation of any information that may become available in discovery.

The Company believes the First Wind Sellers’ allegation is without merit and will contest the claim and allegations 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 and certain individuals, with the United States Department of Labor. The complaint alleges 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 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 constructively terminating his position as Chief Operating Officer of the Company in connection with SunEdison’s constructive 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 of 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. The complaint asserts 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 15, 2017, the Company filed notice with the Judicial Panel on Multidistrict Litigation to transfer this action to the U.S. District Court for the Southern District of New York (“SDNY”) where other cases not involving the Company relating to the SunEdison bankruptcy are being tried. The plaintiff did not oppose the transfer, which 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. Perez’s complaint, and Mr. Perez filed a response on December 21, 2017. On March 8, 2018, Mr. Perez voluntarily dismissed the federal action without prejudice, which would permit the action to be refiled. On December 27, 2018, the proceeding before the Department of Labor was dismissed which Mr. Perez appealed on January 25, 2019.

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, 2018. However, the Company is unable to predict with certainty the ultimate resolution of these proceedings.

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 of 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 asserts 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

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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 refiled his complaint with the United States District Court for the District of Maryland and 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. The proceeding before the Department of Labor is pending.

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, 2018. However, the Company is unable to predict with certainty the ultimate resolution of these proceedings.

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 allege, 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 alleges that it is entitled to damages based on alleged breaches of a call option agreement entered into by the parties. Both respondents delivered their initial responses to the CAM on November 7, 2016. The proceedings are currently in the evidentiary phase. The Company believes these claims are without merit and intends to continue to contest them vigorously. However, the Company cannot predict with certainty the ultimate resolution of the arbitral proceedings brought in connection with these claims.

Issuance of Shares upon Final Resolution of Certain Litigation Matters

Pursuant to the Merger Agreement, the Company has agreed to issue additional shares of Class A 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 (being the Chamblee Class Action and 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 Class A 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 filed on Schedule 14A 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.

On August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Class A common stock to Orion Holdings in connection with the net losses incurred for final resolution of the Chamblee Securities Class Action mentioned above. 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.

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, Mr. Perez 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.

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”). The U.S. Treasury counterclaimed and both claims went to trial in the Court of Federal Claims in July 2018. In January 2019, the Court of Federal Claims entered judgments against each project company for

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approximately $10.0 million in the aggregate, which may be appealed. The project companies 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 prepaid expenses and other current assets in the consolidated balance sheets as of December 31, 2018.

19.RELATED PARTIES

As discussed in Note1.Nature of Operations and Organization, prior to the consummation of the Merger, TerraForm Power was a controlled affiliate of SunEdison. As a result of the consummation of the Merger on October 16, 2017, a change of control of TerraForm Power occurred, and Orion Holdings, which is an affiliate of Brookfield, came to hold 51% of the voting securities of TerraForm Power immediately following the consummation of the Merger. As a result of the Merger closing, TerraForm Power was no longer a controlled affiliate of SunEdison and became a controlled affiliate of Brookfield.

As discussed in Note 1. Nature of Operations and Organization, 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 discussed below under Brookfield Sponsorship Transaction, which adjusted the distribution thresholds and percentages applicable to the IDRs.

Brookfield Sponsorship Transaction

As discussed in Note 1. Nature of Operations and Organization, pursuant to the Merger Agreement, at or prior to the effective time of the Merger that occurred on October 16, 2017, the Company and Orion Holdings (or one of its affiliates), among other parties, entered into a suite of agreements providing for sponsorship arrangements, as are more fully described below.

Brookfield Master Services Agreement

In connection with the consummation of the Merger, 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 master services agreement, 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 Class A 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 Class A 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 a $14.6 million and $3.4 million charge within general and administrative expenses - affiliate in the consolidated statements of operations for the year ended December 31, 2018 and 2017, respectively. The balance payable under the Brookfield MSA was $4.2 million and $3.4 million in the consolidated balance sheets as of December 31, 2018 and 2017.

Sponsor Line Agreement

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On October 16, 2017, TerraForm Power entered into 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 make 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 will terminate, and all obligations thereunder will 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% of the credit facility amount during the year ended December 31, 2017, which is recorded 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.

During the year ended December 31, 2018 the Company made two draws on the Sponsor Line totaling $86 million that were used to fund the acquisition of Saeta and repaid such amounts. As of December 31, 2018 and December 31, 2017, respectively, there were no amounts drawn under the Sponsor Line. Total interest expense incurred on the Sponsor Line for the years ended December 31, 2018 and 2017 amounted to $5.2 million and $0.9 million, respectively.

Relationship Agreement

In connection with the consummation of the Merger, 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, subject to certain terms and conditions, the Company 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.

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.

Brookfield Registration Rights Agreement

The Company also entered into a registration rights agreement (the “Brookfield Registration Rights Agreement”) on October 16, 2017 with Orion Holdings. The Brookfield Registration Rights Agreement governs Orion Holdings’ and the Company’s rights and obligations with respect to the registration for resale of all or a part of the Class A shares that Orion Holdings now holds following the Merger. On June 11, 2018, Orion Holdings, Brookfield BRP Holdings (Canada) Inc. and the

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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.

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 Class A common stock and a second distribution threshold of $1.05 per share of Class A 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 Class A common stock of $0.93 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Class A common stock) if such amount were distributed to all holders of shares of Class A 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 Class A common stock of an additional $0.12 per share (subject to adjustment for distributions, combinations or subdivisions of shares of Class A common stock) if such amount were distributed to all holders of shares of Class A 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, 2018 and 2017.

Other Brookfield Transactions and Agreements

Acquisition of Saeta

On June 11, 2018, pursuant to a support agreement between Brookfield and the Company, Orion Holdings and BBHC Orion Holdco L.P. entered into a Class A Common Stock Purchase Agreement pursuant to which they collectively purchased in a private placement a total of 60,975,609 shares of TerraForm Power’s Class A common stock for a price per share of $10.66, representing total consideration of approximately $650.0 million. As a result of this private placement affiliates of Brookfield held approximately 65% of TerraForm Power’s Class A common stock.

In connection with a bank guarantee issued in support of the Saeta acquisition (Note 4. Acquisitions and Dispositions), 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.

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.

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 $0.8 million of charges within general and administrative expenses - affiliate in the consolidated statements of operations during the year ended December 31, 2018.

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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 purely flow-through, cost-reimbursement basis, and did not result in any fees or other amounts payable by the Company to any Brookfield affiliate. As of December 31, 2018, a total of $1.2 million was paid pursuant to these agreements on a cost-reimbursement basis by the Company to the Brookfield counterparty.

Chamblee Class Action Settlement

As discussed in Note 14. Stockholders’ Equity, on August 3, 2018, pursuant to the Merger Agreement, the Company issued 80,084 shares of Class A 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 affiliate

The $0.2 million and $4.4 million due from affiliate amounts reported in the consolidated balance sheets as of December 31, 2018 and 2017, respectively, each represents a receivable from TerraForm Global, as a result of payments made by the Company on its behalf regarding rent for its shared former corporate headquarters, compensation for certain employees that provided services to both companies and certain information technology services, of which a net $4.8 million was received during the year ended December 31, 2018. There was no right of set-off with respect to these receivables from TerraForm Global 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 $7.0 million due to affiliates amount reported in the consolidated balance sheets as of December 31, 2018, primarily represents 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.

As of December 31, 2017, the $4.0 million due to affiliates amount represented a $3.4 million payable for the Brookfield MSA quarterly base management fee and $0.6 million of accrued standby fee interest that was payable to a Brookfield affiliate under the Sponsor Line. These 2017 year-end payables were paid in the first quarter of 2018, as well as: (i) $10.4 million representing the management fee for the first nine months of 2018; (ii) $4.0 million for services and fees paid on behalf of the Company by affiliates of Brookfield in relation to the acquisition of Saeta; and (iii) $3.0 million of additional Sponsor Line standby fee interest. Additionally, 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.

As discussed above, under the Settlement Agreement, the settlements and mutual intercompany releases became effective upon the consummation of the Merger with affiliates of Brookfield on October 16, 2017, and as a result, the Company wrote-off $15.7 million of payables to SunEdison as of such date. The write-off was recognized in additional paid-in capital as the entire settlement with SunEdison was accounted for as an equity transaction.

As a result of the SunEdison Bankruptcy, the Company recognized $1.8 million and $3.3 million loss within loss on

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investments and receivables - affiliate in the consolidated statements of operations for the years ended December 31, 2017 and 2016, respectively, related to the write-off of outstanding receivables from the SunEdison Debtors.

SunEdison Matters

SunEdison Bankruptcy and Settlement Agreement with SunEdison

As discussed in Note1.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 2015, 2016 and 2017 but not to exceed $4.0 million in 2015, $7.0 million in 2016 or $9.0 million in 2017. 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 and $12.0 million for the years ended December 31, 2017 and 2016, respectively, 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, with the exception of 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 2016, 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

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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.

Historical Interest Payment Agreement with SunEdison

Since the Company's initial public offering (“IPO”) on July 23, 2014, the Company was a party to an interest payment agreement with SunEdison, pursuant to which SunEdison would pay a portion of the scheduled interest payments on certain corporate-level indebtedness. The Company received equity contributions totaling $8.0 million from SunEdison pursuant to this agreement during the year ended December 31, 2016. The 2016 contribution was received in the first quarter of 2016 and accrued for during fiscal 2015. The Company did not receive any payments from SunEdison pursuant to this agreement subsequent to the first quarter of 2016. 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, this agreement was rejected without further liability, claims or damages on the part of the Company.

Historical Support Agreement with SunEdison

The Company entered into a project support agreement with SunEdison (the “SunE Support Agreement”) on July 23, 2014, which provided the Company the option to purchase additional renewable energy facilities from SunEdison and also provided the Company a right of first offer with respect to certain other renewable energy facilities. During the year ended December 31, 2016, the Company acquired renewable energy facilities with a combined nameplate capacity of 19.2 MW from SunEdison under the SunE Support Agreement. The Company did not acquire any renewable energy facilities from SunEdison under the SunE Support Agreement during 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, the SunE Support Agreement was rejected without further liability, claims or damages on the part of the Company.

The Company continues 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 SunEdison (the “AP Warehouse”). SunEdison sold its equity interest in the AP Warehouse to an unaffiliated third party in 2017.

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

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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 18. 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 years ended December 31, 2017 and 2016, 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 years ended December 31, 2017 and 2016 as reported in the consolidated statements of stockholders' equity:

	Year ended December 31,
(in thousands)	2017			2016
General and administrative expenses - affiliate1	$	6,154		$	7,666
TerraForm Power, Inc. equity awards distributed to SunEdison2	(3,372		)	(3,369		)
Deemed contribution related to acquisitions from SunEdison3	—			19,517
Other4	6,986			1,586
Net SunEdison investment	$	9,768		$	25,400

———

(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 15. Stock-based Compensation). The Company did not pay SunEdison the $7.0 million base management fee that it was contractually obligated to in 2016 as the amount the Company had to pay third party service providers to cover the services that SunEdison stopped providing exceeded this contractual amount. Since this fee was not paid to SunEdison as of December 31, 2016, it was recorded within Due to affiliates, net and as a reduction to the net equity contribution from SunEdison. Pursuant to the Settlement Agreement and upon the consummation of the Merger on October 16, 2017, this liability was written off to additional paid-in capital as discussed under Due to affiliates above.

(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 the difference between the cash purchase price and historical cost of the net assets acquired from SunEdison for projects that achieved final funding during the respective year.

(4) Amount for the year ended December 31, 2017 represents cash received from SunEdison in satisfaction of outstanding claims made under engineering, procurement and construction contracts as discussed above.

20. SEGMENT REPORTING

Following the acquisition of Saeta (see Note 4. Acquisitions and Dispositions), the Company’s management performed a review of its segment reporting structure and determined that the Company has three reportable segments: Solar, Wind, and Regulated Solar and Wind. These segments, which are comprised of the Company’s entire portfolio of renewable energy facility assets, 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 are comprised 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

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Company’s Chief Executive Officer and Chief Financial Officer have been identified as the CODM. The Company’s operating segments consist of: (i) Distributed Generation, North America Utility and International Utility, which are aggregated into the Solar reportable segment; (ii) Northeast Wind, Central 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 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 are new operating segments that were added during the second quarter of 2018, and include Saeta’s entire operations. The operating segments have been aggregated as they have similar economic characteristics and meet the aggregation criteria. The CODM evaluates the performance of the Company’s operating segments principally based on operating income or loss. Certain other measures reviewed include Adjusted EBITDA and CAFD. Corporate expenses include general and administrative expenses, acquisition costs, interest expense on corporate-level indebtedness, stock-based compensation and depreciation, accretion and amortization expense. All net operating revenues for the years ended December 31, 2018, 2017 and 2016 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 concerning the Company’s reportable segments for the years endedDecember 31, 2018, 2017 and 2016:

	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
Loss on extinguishment of debt, net	—			—			—			1,480			1,480
Other non-operating income, net	(4,248		)	(108		)	(2,261		)	(8,478		)	(15,095		)
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
Loss on extinguishment of debt, net	—			3,151			77,948			81,099
Gain on sale of renewable energy facilities	(37,116		)	—			—			(37,116		)
Other non-operating expenses (income), net	717			499			(10,535		)	(9,319		)
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

	Year Ended December 31, 2016
(In thousands)	Solar			Wind			Corporate			Total
Operating revenues, net	$	377,488		$	277,068		$	—		$	654,556
Depreciation, accretion and amortization expense	115,050			126,735			1,580			243,365
Impairment of renewable energy facilities	18,951			—			—			18,951
Other operating costs and expenses	121,508			91,613			90,142			303,263
Operating income (loss)	121,979			58,720			(91,722		)	88,977
Interest expense, net	97,123			85,744			127,469			310,336
Other non-operating expenses, net	(1,017		)	1,126			19,545			19,654
Income tax expense	—			—			2,734			2,734
Net income (loss)	$	25,873		$	(28,150	)	$	(241,470	)	$	(243,747	)
Cash Flows
Capital expenditures	$	32,132		$	12,177		$	1,560		$	45,869

———

(1) As of December 31, 2018 and 2017, respectively.

Operating Revenues, net

The following table reflects operating revenues, net for the years endedDecember 31, 2018, 2017 and 2016 by specific customers exceeding 10% of total operating revenue:

		Year Ended December 31,
		2018				2017				2016
(In thousands, except for percentages)	Segment	Amount		Percentage		Amount		Percentage		Amount		Percentage
Comisión Nacional de los Mercados y la Competencia (CNMC)1	Regulated Solar and Wind	$	127,912	16.7	%	N/A		N/A		N/A		N/A
Tennessee Valley Authority2	Wind	N/A		N/A		$	79,773	13.1	%	$	73,068	11.2	%
San Diego Gas & Electric2	Solar	N/A		N/A		63,905		10.5		65,709		10.0

———

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(1) Following the acquisition of Saeta, the Company earned $186.7 million from the Spanish Electricity System For the year ended December 31, 2018 of which $127.9 million was through collections from the Comisión Nacional de los Mercados y la Competencia (“CMNC”), representing 16.7% of its net consolidated operating revenues. The role of the CMNC is to collect funds payable, mainly from the tariffs to end user customers and is responsible for the calculation and the settlement of regulated payments.

(2) These customers did not exceed 10% of total operating revenue for the year ended December 31, 2018.

The following table reflects operating revenues, net earned during the years endedDecember 31, 2018, 2017 and 2016 by geographic location:

	Year Ended December 31,
(In thousands)	2018		2017		2016
United States (including Puerto Rico)	$	473,950	$	519,551	$	528,513
Canada	41,174		44,636		46,378
Spain	186,655		—		—
Portugal	17,269		—		—
United Kingdom	1,597		15,002		51,600
Uruguay	17,302		—		—
Chile	28,623		31,282		28,065
Total operating revenues, net	$	766,570	$	610,471	$	654,556

Long-lived Assets, Net

Long-lived assets, net consist of renewable energy facilities, intangible assets and goodwill as of December 31, 2018 and 2017, as applicable. The following table is a summary of long-lived assets, net by geographic area:

	As of December 31,
(In thousands)	2018		2017
United States (including Puerto Rico)	$	5,030,483	$	5,270,988
Canada	362,829		422,999
Spain	2,503,420		—
Portugal	251,053		—
United Kingdom	13,183		17,284
Uruguay	264,798		—
Chile	161,217		168,440
Total long-lived assets, net	8,586,983		5,879,711
Current assets	501,185		341,536
Other non-current assets	242,186		165,774
Total assets	$	9,330,354	$	6,387,021

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21. 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 Adjustments1			Hedging Activities1			Accumulated Other Comprehensive (Loss) Income
Balance as of December 31, 2015	$	(11,733	)	$	34,633		$	22,900
Net unrealized loss arising during the period (net of zero tax benefit and $406 tax expense, respectively)	(15,039		)	(86		)	(15,125		)
Reclassification of net realized loss into earnings (net of zero tax impact)2	—			15,967			15,967
Other comprehensive (loss) income	(15,039		)	15,881			842
Accumulated other comprehensive (loss) income	(26,772		)	50,514			23,742
Less: Other comprehensive (loss) income attributable to non-controlling interests	(4,639		)	5,469			830
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)3	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 exchange4	(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)5	—			(4,164		)	(4,164		)
Cumulative-effect adjustment (net of tax expense of $9,357)6	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

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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) Includes $16.9 million loss reclassification that occurred subsequent to the Company's discontinuation of hedge accounting for interest rate swaps within the U.K. Portfolio as discussed in Note 12. Derivatives.

(3) 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 as discussed in Note 4.Acquisitions and Dispositions. 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.

(4) 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 17. Non-controlling Interests.

(5) 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.

(6) 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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22. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly 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	)

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(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 solar project (see Note5. 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) On June 12, 2018 the Company acquired approximately 95.28% of the outstanding shares of Saeta, a Spanish renewable power company with then-1,028 MW of wind and solar facilities (approximately 250 MW of solar and 778 MW of wind) located primarily in Spain. The Company pursued a statutory squeeze out procedure under Spanish law to procure the remaining approximately 4.72% of the shares of Saeta on July 2, 2018 (see Note4.Acquisitions and Dispositions). Saeta contributed the below to the Company’s results for the year ended December 31, 2018:

(In thousands, except per share data)	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 Note12. Derivatives).

(5) During the fourth quarter of 2018, the Company revised the accretion period related to its wind projects and determined that these obligations should be accreted to expected future value over the remaining useful life of the corresponding renewable energy facility rather than the terms of the related PPAs. This change in accretion period resulted in a $15.7 million reduction in the Company’s previously reported accretion and depreciation expense by $6.3 million, of which $4.4 million of the accretion and depreciation expense reduction related to amounts previously reported for the years ended December 31, 2017, 2016 and 2015. The quarterly accretion and depreciation expense reduction that relates to each of the first three quarters of 2018 was $0.5 million.

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Quarterly results of operations for the year ended December 31, 2017 were as follows:

(In thousands, except per share data)	Q1			Q21			Q32			Q43
Operating revenues, net	$	151,135		$	170,367		$	153,430		$	135,539
Operating income (loss)	12,068			25,547			24,686			(21,578		)
Interest expense, net	68,312			68,205			70,232			55,254
Net loss	(56,622		)	(1,523		)	(36,354		)	(141,804		)
Net (loss) income attributable to Class A common stockholders	(30,797		)	9,606			(26,300		)	(112,663		)
Weighted average Class A common shares outstanding - basic	92,072			92,257			92,352			138,401
Weighted average Class A common shares outstanding - diluted	92,072			92,745			92,352			138,401
Net (loss) earnings per weighted average Class A common share - basic and diluted	$	(0.36	)	$	0.08		$	(0.31	)	$	(0.82	)

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(1) The Company closed on the sale of the U.K. Portfolio during the second quarter of 2017 and 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.

(2) The Company entered into a settlement agreement in 2017 with insurers of one of its wind power plants with respect to insurance proceeds related to a battery fire that occurred at the wind power plant in 2012, and the Company received the insurance proceeds in the fourth quarter of 2017. The receipt of the proceeds became probable in the third quarter of 2017, and the Company recognized a $5.3 million gain in other (income) expenses, net.

(3) The fourth quarter of 2017 includes a $78.6 million loss on extinguishment of debt, which is comprised of charges related to the Revolver, the Senior Notes due 2023 and the Midco Portfolio Term Loan (as discussed in Note 10. Long-term Debt), $27.0 million of charges recorded within general and administrative expenses related to success fees and advisory fees paid to third party advisers upon the closing of the Merger and a $7.0 million stock-based compensation charge recognized within general and administrative expenses as a result of the vesting of all previously unvested equity awards issued under the 2014 LTIP upon the consummation of the Merger. These charges were partially offset by a $6.4 million increase recorded to the income tax benefit in the fourth quarter of 2017 to adjust amounts previously reported in 2016 as discussed in Note 12. Income Taxes and a $4 million gain recognized within general and administrative expenses as a result of the final settlement of the EMEC litigation as discussed in Note 18. Commitments and Contingencies.

23. SUBSEQUENT EVENTS

First Quarter 2019 Dividends

On March 13, 2019, the Board declared a quarterly dividend with respect to our Class A common stock of $0.2014 per share. The dividend is payable on March 29, 2019 to stockholders of record as of March 24, 2019.

EXHIBIT INDEX

Exhibit Number	Description
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).

157

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	Second Amended and Restated Bylaws of TerraForm Power, Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 8-K filed on October 17, 2017).
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.
4.3	Indenture, dated as of July 17, 2015, by and among TerraForm Power Operating, LLC, each of the Guarantors party hereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended September 30, 2015).
4.4	Third Supplemental Indenture, dated as of August 29, 2016, among TerraForm Power Operating, LLC, the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 31, 2016).
4.5	Fifth Supplemental Indenture, dated as of October 16, 2017, among TerraForm Power Operating, LLC, as issuer, the Guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on October 17, 2017).
4.6	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).
4.7	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).
4.8	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).
4.9	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).
10.1	Settlement Agreement, dated as of March 6, 2017, by and among TerraForm Power, Inc., TerraForm Power, LLC, TerraForm Power Operating, LLC, SunEdison Inc. and the other parties named therein (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K filed on March 7, 2017).
10.2	Voting and Support Agreement, dated as of March 6, 2017, by and among Orion US Holdings 1 L.P., BRE TERP Holdings Inc., SunEdison, Inc., SunEdison Holdings Corporation, SUNE ML1, LLC and TerraForm Power, Inc. (incorporated by reference to Exhibit 2.3 to the Registrant’s Form 8-K filed on March 7, 2017).
10.3*	TerraForm Power, Inc. 2018 Third Amended and Restated Long-Term Incentive Plan.+
10.4	Transition Services Agreement, dated September 7, 2017, between TerraForm Power, LLC and SunEdison, Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Periodic Report on Form 8-K filed on September 11, 2017).
10.5	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).
10.6	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).
10.7	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).
10.8	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).

158

10.9	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).
10.10	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).
10.11	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).
10.12*	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.
10.13*	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.
10.14	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).
10.15	Term Loan and Guaranty Agreement, dated as of November 8, 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 Royal Bank of Canada, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on November 13, 2017).
10.16	Amendment No. 1 to Term Loan and Guaranty Agreement, dated as of May 11, 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 Royal Bank of Canada as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on May 18, 2018).
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	Support Agreement, dated February 6, 2018, between Brookfield Asset Management Inc. and TerraForm Power, Inc. (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on February 8, 2018).
10.21	Support Agreement Amendment, dated May 28, 2018, between Brookfield Asset Management Inc. and TerraForm Power, Inc. (incorporated by reference to Exhibit 10.24 to the Registrant’s Registration Statement Form S-1/A, File No. 333-223753, filed on May 29, 2018).

159

10.22	Continuing Agreement for Letters of Credit, dated as of March 6, 2018, by TERP Spanish HoldCo, S.L. and Natixis, New York Branch (incorporated by reference to Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017).
10.23	Letter Agreement, dated as of March 6, 2018, by TerraForm Power, Inc. and Natixis, New York Branch (incorporated by reference to Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017).
10.24	Agreement for Bank Guarantee, dated as of March 6, 2018, by TERP Spanish HoldCo, S.L. and Banco Santander, S.A. (incorporated by reference to Exhibit 10.21 to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017).
10.25	Letter Agreement, dated as of March 6, 2018, by TerraForm Power, Inc. and Banco Santander, S.A. (incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017).
10.26	Class A Common Stock Purchase Agreement, dated as of June 11, 2018, by and between TerraForm Power, Inc., a Delaware corporation, Orion US Holdings 1 LP, a Delaware limited partnership, and Brookfield BRP Holdings (Canada) Inc., an Ontario corporation (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on June 12, 2018).
10.27	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).
10.28	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).
10.29	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).
10.30	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).
16.1	KPMG Report of Independent Registered Public Accounting Firm on the Effectiveness of Internal Control Over Financial Reporting to the Board of Directors of TerraForm Power, Inc., dated as of July 21, 2017 (incorporated by reference to Exhibit 16.1 to the Registrant’s Form 8-K filed on March 19, 2018).
16.2	KPMG Report of Independent Registered Public Accounting Firm on the Effectiveness of Internal Control Over Financial Reporting to the Stockholders and Board of Directors of TerraForm Power, Inc., dated as of March 7, 2018 (incorporated by reference to Exhibit 16.2 to the Registrant’s Form 8-K filed on March 19, 2018).
16.3	Letter from KPMG to the Securities and Exchange Commission, dated as of March 19, 2018 (incorporated by reference to Exhibit 16.3 to the Registrant’s Form 8-K filed on March 19, 2018).
21.1*	List of Subsidiaries of TerraForm Power, Inc. as of December 31, 2018.
23.1*	Consent of KPMG LLP
23.2*	Consent of Ernst & Young LLP
23.3*	Consent of Deloitte, S.L.
23.4*	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**

160

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

------

* Filed as an exhibit to this Annual Report on Form 10-K.

** 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 pursuant to Item 601(b)(2) of Regulation S-K. Registrant agrees to furnish a supplementary copy of any omitted attachment to the Securities and Exchange Commission upon request.

+ Indicates a management contract or compensatory plan or arrangement.

161

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 15, 2019	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 15, 2019
John Stinebaugh	(Principal executive officer)
/s/ MICHAEL TEBBUTT	Chief Financial Officer	March 15, 2019
Michael Tebbutt	(Principal financial officer)
/s/ MICHAEL RAGUSA	Chief Accounting Officer	March 15, 2019
Michael Ragusa	(Principal accounting officer)
/s/ BRIAN LAWSON	Director and Chairman	March 15, 2019
Brian Lawson
/s/ CAROLYN BURKE	Director	March 15, 2019
Carolyn Burke
/s/ CHRISTIAN S. FONG	Director	March 15, 2019
Christian S. Fong
/s/ HARRY GOLDGUT	Director	March 15, 2019
Harry Goldgut
/s/ RICHARD LEGAULT	Director	March 15, 2019
Richard Legault
/s/ MARK MCFARLAND	Director	March 15, 2019
Mark McFarland
/s/ SACHIN SHAH	Director	March 15, 2019
Sachin Shah

162