Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 _____________________________________________________________________________
FORM 10-Q
 _____________________________________________________________________________
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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
 ______________________________________________________________
image0a18.jpg
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)
 _________________________________________________
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 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 October 31, 2018, there were 209,141,720 shares of Class A common stock outstanding.
 



TerraForm Power, Inc. and Subsidiaries
Table of Contents
Form 10-Q

 
 
Page
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
 
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 




CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q 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,” “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, earnings, revenues, capital expenditures, liquidity, capital structure, 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 the transition to Brookfield Asset Management Inc. sponsorship, including our ability to realize the expected benefits of the sponsorship;
•
risks related to wind conditions at our wind assets or to weather conditions at our solar assets;
•
risks related to the effectiveness of our internal control over financial reporting;
•
pending and future litigation;
•
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;
•
our ability to compete against traditional and renewable energy companies;
•
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;
•
the condition of the debt and equity capital markets and our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness in the future;
•
operating and financial restrictions placed on us and our subsidiaries related to agreements governing indebtedness;
•
risks related to our ability to successfully integrate the operations, technologies and personnel of Saeta Yield S.A.U. (“Saeta”) and to establish appropriate accounting controls in respect of Saeta;
•
the regulated rate of return of renewable energy facilities in Spain, including Saeta’s wind and solar assets, a reduction of which could have a material negative impact on our results of operations;
•
our ability to successfully identify, evaluate and consummate acquisitions;
•
our ability to integrate the projects we acquire from third parties, including Saeta, and our ability to realize the anticipated benefits from such acquisitions; and
•
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.

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 our Annual Report on Form 10-K for the year ended December 31, 2017 and in subsequent Quarterly Reports on Form 10-Q, as well as additional factors we may describe from time to time in our other filings with the Securities and Exchange Commission (the “SEC”). We operate in a competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and you should understand that it is not possible to predict or identify all such factors and, consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.



3


PART I - Financial Information

Item 1. Financial Statements.

TERRAFORM POWER, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)


 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Operating revenues, net
$
246,042

 
$
153,430

 
$
553,477

 
$
474,932

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of operations
59,027

 
41,859

 
146,155

 
108,402

Cost of operations - affiliate
—

 
1,199

 
—

 
10,224

General and administrative expenses
21,334

 
21,664

 
65,483

 
99,644

General and administrative expenses - affiliate
3,432

 
2,192

 
10,929

 
6,893

Acquisition-related costs
1,655

 
—

 
7,612

 
—

Acquisition-related costs - affiliate
335

 
—

 
6,965

 
—

Impairment of renewable energy facilities
—

 
—

 
15,240

 
1,429

Depreciation, accretion and amortization expense
103,593

 
61,830

 
239,177

 
186,039

Total operating costs and expenses
189,376

 
128,744

 
491,561

 
412,631

Operating income
56,666

 
24,686

 
61,916

 
62,301

Other expenses (income):
 
 
 
 
 
 
 
Interest expense, net
72,416

 
70,232

 
176,862

 
206,749

Gain on sale of renewable energy facilities
—

 
—

 
—

 
(37,116
)
Gain on foreign currency exchange, net
(3,070
)
 
(1,078
)
 
(4,257
)
 
(5,695
)
Other expenses (income), net
358

 
(7,015
)
 
2,870

 
(4,882
)
Total other expenses, net
69,704

 
62,139

 
175,475

 
159,056

Loss before income tax expense (benefit)
(13,038
)
 
(37,453
)
 
(113,559
)
 
(96,755
)
Income tax expense (benefit)
6,013

 
(1,099
)
 
9,417

 
(2,256
)
Net loss
(19,051
)
 
(36,354
)
 
(122,976
)
 
(94,499
)
Less: Net income attributable to redeemable non-controlling interests
12,443

 
4,895

 
15,101

 
10,264

Less: Net income (loss) attributable to non-controlling interests
2,096

 
(14,949
)
 
(165,946
)
 
(57,272
)
Net (loss) income attributable to Class A common stockholders
$
(33,590
)
 
$
(26,300
)
 
$
27,869

 
$
(47,491
)
 
 
 
 
 
 
 
 
Weighted average number of shares:
 
 
 
 
 
 
 
Class A common stock - Basic
209,142

 
92,352

 
173,173

 
92,228

Class A common stock - Diluted
209,142

 
92,352

 
173,186

 
92,228

 
 
 
 
 
 
 
 
(Loss) earnings per share:
 
 
 
 
 
 
 
Class A common stock - Basic and diluted
$
(0.16
)
 
$
(0.31
)
 
$
0.16

 
$
(0.59
)
 
 
 
 
 
 
 
 
Dividends declared per share:
 
 
 
 
 
 
 
Class A common stock
$
0.19

 
$
—

 
$
0.57

 
$
—



See accompanying notes to unaudited condensed consolidated financial statements.

4


TERRAFORM POWER, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)



 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
Net loss
 
$
(19,051
)
 
$
(36,354
)
 
$
(122,976
)
 
$
(94,499
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
Foreign currency translation adjustments:
 
 
 
 
 
 
 
 
Net unrealized gain (loss) arising during the period
 
446

 
6,535

 
(8,229
)
 
12,136

Reclassification of net realized loss into earnings1
 
—

 
—

 
—

 
14,741

Hedging activities:
 
 
 
 
 
 
 
 
Net unrealized gain arising during the period
 
10,621

 
17,338

 
12,528

 
27,960

Reclassification of net realized (gain) loss into earnings
 
(5,832
)
 
94

 
(6,755
)
 
(527
)
Other comprehensive income (loss), net of tax
 
5,235

 
23,967

 
(2,456
)
 
54,310

Total comprehensive (loss)
 
(13,816
)
 
(12,387
)
 
(125,432
)
 
(40,189
)
Less comprehensive income attributable to non-controlling interests:
 
 
 
 
 
 
 
 
Net income attributable to redeemable non-controlling interests
 
12,443

 
4,895

 
15,101

 
10,264

Net income (loss) attributable to non-controlling interests
 
2,096

 
(14,949
)
 
(165,946
)
 
(57,272
)
Foreign currency translation adjustments
 
—

 
1,967

 
—

 
1,250

Hedging activities
 
(1,801
)
 
6,799

 
(3,038
)
 
18,638

Comprehensive income (loss) attributable to non-controlling interests
 
12,738

 
(1,288
)
 
(153,883
)
 
(27,120
)
Comprehensive (loss) income attributable to Class A common stockholders
 
$
(26,554
)
 
$
(11,099
)
 
$
28,451

 
$
(13,069
)
———
(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 unaudited condensed consolidated statements of operations for the nine months ended September 30, 2017.



See accompanying notes to unaudited condensed consolidated financial statements.

5


TERRAFORM POWER, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)


 
September 30,
2018
 
December 31, 2017
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
349,563

 
$
128,087

Restricted cash
28,095

 
54,006

Accounts receivable, net
178,094

 
89,680

Prepaid expenses and other current assets
71,935

 
65,393

Due from affiliate
350

 
4,370

Total current assets
628,037

 
341,536

 
 
 
 
Renewable energy facilities, net, including consolidated variable interest entities of $3,119,285 and $3,273,848 in 2018 and 2017, respectively
6,555,836

 
4,801,925

Intangible assets, net, including consolidated variable interest entities of $761,299 and $823,629 in 2018 and 2017, respectively
2,000,893

 
1,077,786

Goodwill
113,701

 
—

Restricted cash
132,337

 
42,694

Other assets
145,173

 
123,080

Total assets
$
9,575,977

 
$
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 $59,210 and $84,691 in 2018 and 2017, respectively
$
454,351

 
$
403,488

Accounts payable, accrued expenses and other current liabilities, including consolidated variable interest entities of $37,862 and $34,199 in 2018 and 2017, respectively
207,185

 
88,538

Deferred revenue
1,720

 
17,859

Due to affiliates
10,921

 
3,968

Total current liabilities
674,177

 
513,853

 
 
 
 
Long-term debt and financing lease obligations, less current portion, including consolidated variable interest entities of $908,962 and $833,388 in 2018 and 2017, respectively
5,499,731

 
3,195,312

Deferred revenue, less current portion
12,444

 
38,074

Deferred income taxes
204,157

 
24,972

Asset retirement obligations, including consolidated variable interest entities of $98,955 and $97,467 in 2018 and 2017, respectively
173,202

 
154,515

Other long-term liabilities
155,278

 
37,923

Total liabilities
6,718,989

 
3,964,649

 
 
 
 
Redeemable non-controlling interests
43,900

 
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
2,427,612

 
1,872,125

Accumulated deficit
(334,757
)
 
(387,204
)
Accumulated other comprehensive income
44,436

 
48,018

Treasury stock, 500,420 shares in 2018 and 2017
(6,712
)
 
(6,712
)
Total TerraForm Power, Inc. stockholders' equity
2,132,675

 
1,527,713

Non-controlling interests
680,413

 
859,999

Total stockholders' equity
2,813,088

 
2,387,712

Total liabilities, redeemable non-controlling interests and stockholders' equity
$
9,575,977

 
$
6,387,021


See accompanying notes to unaudited condensed consolidated financial statements.

6


TERRAFORM POWER, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In thousands)


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-controlling Interests
 
 
 
Class A Common Stock Issued
 
Additional Paid-in Capital
 
Accumulated Deficit
 
Accumulated Other Comprehensive Income
 
Common Stock Held in Treasury
 
 
 
 
 
Accumulated Deficit
 
Accumulated Other Comprehensive Income (Loss)
 
 
 
Total Equity
 
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
—

 
—

 
—

 
24,578

 
(4,164
)
 
—

 
—

 
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
—

 
—

 
161

 
—

 
—

 
—

 
—

 
161

 
—

 
—

 
—

 
—

 
161

Net income (loss)
—

 
—

 
—

 
27,869

 
—

 
—

 
—

 
27,869

 
—

 
(165,946
)
 
—

 
(165,946
)
 
(138,077
)
Dividends
—

 
—

 
(95,625
)
 
—

 
—

 
—

 
—

 
(95,625
)
 
—

 
—

 
—

 
—

 
(95,625
)
Other comprehensive income (loss)
—

 
—

 
—

 
—

 
582

 
—

 
—

 
582

 
—

 
—

 
(3,038
)
 
(3,038
)
 
(2,456
)
Contributions from non-controlling interests in renewable energy facilities
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
7,685

 
—

 
—

 
7,685

 
7,685

Distributions to non-controlling interests in renewable energy facilities
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(17,888
)
 
—

 
—

 
(17,888
)
 
(17,888
)
Purchase of redeemable non-controlling interests in renewable energy facilities
—

 
—


(3,065
)
 
—

 
—

 
—

 
—

 
(3,065
)
 
—

 
—

 
—

 
—

 
(3,065
)
Other
—

 
—

 
3,745

 
—

 
—

 
—

 
—

 
3,745

 
409

 
(500
)
 
—

 
(91
)
 
3,654

Balance as of September 30, 2018
209,642

 
$
2,096

 
$
2,427,612

 
$
(334,757
)
 
$
44,436

 
(500
)
 
$
(6,712
)
 
$
2,132,675

 
$
1,047,507

 
$
(364,950
)
 
$
(2,144
)
 
$
680,413

 
$
2,813,088

———
(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 and ASU No. 2017-12 as of January 1, 2018.


See accompanying notes to unaudited condensed consolidated financial statements.

7


TERRAFORM POWER, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


 
Nine Months Ended September 30,
2018
 
2017
Cash flows from operating activities:
 
 
 
Net loss
$
(122,976
)
 
$
(94,499
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, accretion and amortization expense
239,177

 
186,039

Amortization of favorable and unfavorable rate revenue contracts, net
29,477

 
29,459

Gain on sale of renewable energy facilities
—

 
(37,116
)
Impairment of renewable energy facilities
15,240

 
1,429

Amortization of deferred financing costs and debt discounts
7,969

 
19,729

Unrealized (gain) loss on interest rate swaps
(11,688
)
 
2,425

Unrealized gain on commodity contract derivatives, net
(3,845
)
 
(1,244
)
Recognition of deferred revenue
(1,344
)
 
(11,510
)
Stock-based compensation expense
161

 
7,049

Loss on extinguishment of debt, net
1,480

 
2,518

Loss on disposal of property, plant and equipment
6,764

 
—

Unrealized gain on foreign currency exchange, net
(9,643
)
 
(5,275
)
Deferred taxes
4,888

 
7,892

Other, net
453

 
5,978

Changes in assets and liabilities:
 
 
 
Accounts receivable
(18,757
)
 
(18,860
)
Prepaid expenses and other current assets
9,154

 
(4,997
)
Accounts payable, accrued expenses and other current liabilities
(13,002
)
 
(758
)
Due to affiliates
4,158

 
199

Other non-current assets and liabilities, net
13,361

 
3,907

Net cash provided by operating activities
151,027

 
92,365

Cash flows from investing activities:
 
 
 
Capital expenditures
(15,320
)
 
(7,472
)
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
8,224

 
23,621

Proceeds from the settlement of foreign currency contracts
22,429

 
—

Acquisition of Saeta business, net of cash and restricted cash acquired
(886,104
)
 
—

Acquisition of renewable energy facilities from third parties, net of cash and restricted cash acquired
(4,105
)
 
—

Net cash (used in) provided by investing activities
(874,876
)
 
199,384


See accompanying notes to unaudited condensed consolidated financial statements.

8


TERRAFORM POWER, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(CONTINUED)

 
Nine Months Ended September 30,
2018
 
2017
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
)
 
—

Revolving credit facility draws
619,000

 
—

Revolving credit facility repayments
(200,466
)
 
(275,000
)
Term Loan principal payments
(2,625
)
 
—

Borrowings of non-recourse long-term debt
236,381

 
79,835

Principal payments and prepayments on non-recourse long-term debt
(180,124
)
 
(199,481
)
Debt financing fees
(7,422
)
 
(10,228
)
Sale of membership interests and contributions from non-controlling interests in renewable energy facilities
7,685

 
6,935

Purchase of membership interests and distributions to non-controlling
interests in renewable energy facilities
(21,792
)
 
(23,017
)
Due to/from affiliates, net
4,803

 
(3,097
)
Net SunEdison investment
—

 
7,436

Payment of dividends
(95,627
)
 
—

Recovery of related party short swing profit
2,994

 
—

Other financing activities
—

 
(1,030
)
Net cash provided by (used in) financing activities
1,012,807

 
(417,647
)
Net increase in cash, cash equivalents and restricted cash
288,958

 
(125,898
)
Net change in cash, cash equivalents and restricted cash classified within assets held for sale
—

 
54,806

Effect of exchange rate changes on cash, cash equivalents and restricted cash
(3,750
)
 
3,264

Cash, cash equivalents and restricted cash at beginning of period
224,787

 
682,837

Cash, cash equivalents and restricted cash at end of period
$
509,995

 
$
615,009

Supplemental Disclosures:
 
 
 
Cash paid for interest
$
170,549

 
$
182,021

Cash paid for income taxes
667

 
—


See accompanying notes to unaudited condensed consolidated financial statements.

9


TERRAFORM POWER, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except per share data, unless otherwise noted)


1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 produced 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 has an objective to acquire operating solar and wind assets in North America and Western Europe.
    
On October 16, 2017, BRE TERP Holdings Inc., a wholly-owned subsidiary of Orion US Holdings 1 L.P. (“Orion Holdings”), merged with and into TerraForm Power, with TerraForm Power continuing as the surviving corporation (the “Merger”). Prior to the consummation of the Merger, TerraForm Power and its subsidiaries were controlled affiliates of SunEdison, Inc. (together with its consolidated subsidiaries excluding the Company and TerraForm Global, Inc. and its subsidiaries, “SunEdison”). As a result of the consummation of the Merger, a change of control of TerraForm Power occurred, and Orion Holdings, which is a controlled affiliate of Brookfield, held 51% of the voting securities of TerraForm Power immediately following the Merger consummation. 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. As further discussed in Note 12. Stockholders’ Equity, on June 11, 2018, Orion Holdings and Brookfield BRP Holdings (Canada) Inc. (“BEP”), an Ontario Corporation and an affiliate of Brookfield, 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 as of September 30, 2018.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated and have been prepared in accordance with the SEC regulations for interim financial information. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements. The financial statements should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company’s annual financial statements for the year ended December 31, 2017, filed with the SEC on Form 10-K on March 7, 2018. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company’s financial position as of September 30, 2018, results of operations and comprehensive (loss) income for the three and nine months ended September 30, 2018 and 2017 and cash flows for the nine months ended September 30, 2018 and 2017.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

In preparing the unaudited condensed consolidated financial statements, the Company used 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.



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Reconciliation of Cash and Cash Equivalents and Restricted Cash as Presented in the Unaudited Condensed Consolidated Statement of Cash Flows

The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the unaudited condensed consolidated balance sheets to the total of the same such amounts shown in the unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2018.
(In thousands)
 
September 30,
2018
 
December 31,
2017
Cash and cash equivalents
 
$
349,563

 
$
128,087

Restricted cash - current
 
28,095

 
54,006

Restricted cash - non-current
 
132,337

 
42,694

Cash, cash equivalents and restricted cash shown in the unaudited condensed consolidated statement of cash flows
 
$
509,995

 
$
224,787


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 balance sheet date.

As discussed in Note 8. 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 nine months ended September 30, 2018 and for the year ended December 31, 2017. As a result, the Company reclassified $11.7 million and $18.8 million of non-current restricted cash to current as of September 30, 2018 and December 31, 2017, respectively, consistent with the corresponding debt classification, as the restrictions that required the cash balances to be classified as non-current restricted cash were driven by the financing agreements. As of September 30, 2018, and December 31, 2017, $2.7 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.

Non-controlling Interests - Impact of the Tax Cuts and Jobs Act Enactment

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”), 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 hypothetical liquidation at book value (“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 nine months ended September 30, 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.

Restructuring

In connection with the consummation of the Merger and the relocation of the headquarters of the Company to New York, New York, the Company announced a restructuring plan that went into effect upon the closing of the Merger, which was substantially completed early in the third quarter of 2018. The Company recognized $0.5 million and $2.7 million of additional severance and transition bonus costs during the three and nine months ended September 30, 2018, respectively, within general and administrative expenses in the unaudited condensed consolidated statements of operations. The Company made $2.7 million and $4.9 million of payments related to this restructuring during the three and nine months ended September 30, 2018, respectively. The balance of the accrued severance and transition bonuses was $0.5 million as of September 30, 2018.



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Recently Adopted Accounting Standards - Guidance Adopted in 2018

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 further 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 power purchase agreements (“PPAs”), individual renewable energy certificate (“REC”) sales, and upfront sales of federal & state incentive benefits recorded as deferred revenue and accreted into revenue. 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. See Note 3. Revenue for additional disclosures required by the new guidance.
    
The Company accounts for the majority of its PPAs as operating leases under Accounting Standards Codification (“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 and therefore these PPAs are currently being evaluated in anticipation of the new lease standard adoption in fiscal 2019. 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 Note 3. Revenue for the new revenue recognition policy.

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 unaudited condensed consolidated statement of stockholders’ equity for the nine months ended September 30, 2018, and the redeemable non-controlling interests adjustment is reflected within cumulative-effect adjustment in the redeemable non-controlling interests roll-forward presented above. The impact on the Company’s results of operations for the first nine months of 2018 was minimal and is expected to be minimal for the remainder of 2018.

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 sheet, and subsequently, one-fifth of the amounts allocated to the ITCs was recognized annually as incentives revenue in the consolidated statement 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 unaudited condensed consolidated statement of stockholders’ equity for the nine months ended September 30, 2018. The impact on the Company’s results of operations for the three and nine months ended September 30, 2018 resulted in a decrease in non-cash deferred revenue recognition of $5.0 million and $10.1 million, respectively, and is expected to result in a decrease in non-cash deferred revenue recognition of approximately $6.2 million for the remainder of 2018.


12



In August 2016, the FASB issued ASU No. 2016-15, Statement of 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 statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The 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 should 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 the tendered shares of Saeta on June 12, 2018 qualifies to be accounted for as an acquisition of a business and the Company’s acquisition of a 6 megawatt (“MW”) portfolio of operating solar distributed generation assets located in California and New Jersey on June 29, 2018 should be accounted for as an acquisition of assets. See Note 4. Acquisitions and Dispositions for further discussion of the Saeta acquisition.

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 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 nine months ended September 30, 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 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


13



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:

•
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 unaudited condensed consolidated statement of stockholders’ equity for the nine months ended September 30, 2018.

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 9. Income Taxes 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. The Company expects to adopt the guidance on January 1, 2019. The issued guidance requires a modified retrospective transition approach, which requires entities to recognize and measure leases at the beginning of the earliest period presented. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842), Targeted Improvements, which amended the standard to give entities another option for transition. The additional transition method allows entities to initially apply the requirements of the standard in the period of adoption (January 1, 2019). The Company is assessing this transition option. The Company expects to elect 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. In January 2018, the FASB issued additional guidance which provides another optional transition practical expedient that allows entities to not evaluate existing and expired land easements under the new guidance at adoption if they were not previously accounted for as leases. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts which may contain embedded leases.

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 will be 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


14



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

In August 2018, the FASB issued ASU No. 2018-13, 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 three and nine months ended September 30, 2018, and provide a reconciliation of the adoption impact of Topic 606 on the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018, and unaudited condensed consolidated balance sheet as of September 30, 2018. There was no net impact on net cash provided by operating activities in the unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2018 resulting from the adoption of Topic 606.

Topic 606 Adoption Impact on Unaudited Condensed Consolidated Statements of Operations
 
 
Three Months Ended September 30, 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
 
$
66,982

 
$
35,084

 
$
—

 
$
102,066

 
$
—

 
$
—

 
$
102,066

Commodity derivatives
 
—

 
7,469

 
—

 
7,469

 
—

 
—

 
7,469

PPA and market energy revenue
 
14,353

 
18,846

 
32,594

 
65,793

 
—

 
—

 
65,793

Capacity revenue from remuneration programs1
 
—

 
—

 
47,356

 
47,356

 
—

 
—

 
47,356

Amortization of favorable and unfavorable rate revenue contracts, net
 
(2,132
)
 
(7,779
)
 
—

 
(9,911
)
 
—

 
—

 
(9,911
)
Energy revenue
 
79,203

 
53,620

 
79,950

 
212,773

 
—

 
—

 
212,773

Incentive revenue
 
15,680

 
3,343

 
14,246

 
33,269

 
2,318

 
4,958

 
40,545

Operating revenues, net
 
94,883

 
56,963

 
94,196

 
246,042

 
2,318

 
4,958

 
253,318

Operating costs and expenses
 
 
 
 
 
 
 
189,376

 
—

 
—

 
189,376

Operating income
 
 
 
 
 
 
 
56,666

 
2,318

 
4,958

 
63,942

Other expenses, net
 
 
 
 
 
 
 
69,704

 
—

 
—

 
69,704

(Loss) income before income tax expense
 
 
 
 
 
 
 
(13,038
)
 
2,318

 
4,958

 
(5,762
)
Income tax expense
 
 
 
 
 
 
 
6,013

 
—

 
—

 
6,013

Net loss
 
 
 
 
 
 
 
$
(19,051
)
 
$
2,318

 
$
4,958

 
$
(11,775
)


16



 
 
Nine Months Ended September 30, 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
 
$
159,116

 
$
138,396

 
$
—

 
$
297,512

 
$
—

 
$
—

 
$
297,512

Commodity derivatives
 
—

 
39,917

 
—

 
39,917

 
—

 
—

 
39,917

PPA and market energy revenue
 
34,318

 
31,897

 
38,909

 
105,124

 
—

 
—

 
105,124

Capacity revenue from remuneration programs1
 
—

 
—

 
59,327

 
59,327

 
—

 
—

 
59,327

Amortization of favorable and unfavorable rate revenue contracts, net
 
(6,075
)
 
(23,403
)
 
—

 
(29,478
)
 
—

 
—

 
(29,478
)
Energy revenue
 
187,359

 
186,807

 
98,236

 
472,402

 
—

 
—

 
472,402

Incentive revenue
 
50,568

 
13,261

 
17,246

 
81,075

 
5,344

 
10,074

 
96,493

Operating revenues, net
 
237,927

 
200,068

 
115,482

 
553,477

 
5,344

 
10,074

 
568,895

Operating costs and expenses
 
 
 
 
 
 
 
491,561

 
—

 
—

 
491,561

Operating income
 
 
 
 
 
 
 
61,916

 
5,344

 
10,074

 
77,334

Other expenses, net
 
 
 
 
 
 
 
175,475

 
—

 
—

 
175,475

Loss before income tax expense
 
 
 
 
 
 
 
(113,559
)
 
5,344

 
10,074

 
(98,141
)
Income tax expense
 
 
 
 
 
 
 
9,417

 
—

 
—

 
9,417

Net (loss) income
 
 
 
 
 
 
 
$
(122,976
)
 
$
5,344

 
$
10,074

 
$
(107,558
)
———
(1)
Represents the remuneration related to the Company’s investments associated with its renewable energy facilities in Spain, as discussed below in “Regulated solar and wind revenue”.

Topic 606 Adoption Impact on Unaudited Condensed Consolidated Balance Sheet
 
 
As of September 30, 2018
 
 
As
Reported
 
Adjustments
 
Amounts excluding Topic 606 Adoption
(In thousands)
 
 
REC Sales
 
ITC Sales
 
Accounts receivable, net
 
$
178,094

 
$
30,619

 
$
—

 
$
208,713

Other current assets
 
449,943

 
—

 
—

 
449,943

Total current assets
 
628,037

 
30,619

 
—

 
658,656

Non-current assets
 
8,947,940

 
—

 
—

 
8,947,940

Total assets
 
$
9,575,977

 
$
30,619

 
$
—

 
$
9,606,596

 
 
 
 
 
 
 
 
 
Deferred revenue
 
$
1,720

 
$
—

 
$
16,310

 
$
18,030

Other current liabilities
 
672,457

 
—

 
—

 
672,457

Total current liabilities
 
674,177

 
—

 
16,310

 
690,487

Deferred revenue, less current portion
 
12,444

 
—

 
14,513

 
26,957

Other non-current liabilities
 
6,032,368

 
—

 
—

 
6,032,368

Total liabilities
 
6,718,989

 
—

 
30,823

 
6,749,812

Redeemable non-controlling interests and total stockholders’ equity
 
2,856,988

 
30,619

 
(30,823
)
 
2,856,784

Total liabilities, redeemable non-controlling interests and stockholders’ equity
 
$
9,575,977

 
$
30,619

 
$
—

 
$
9,606,596


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


17



Company will adopt ASC 842, Leases on January 1, 2019. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard and may elect 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 unaudited condensed 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 10. 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 kilowatt hours (“kWhs”) which can vary period to period depending on system and resource availability. The contract rate per unit of generation (kWhs) is generally fixed at contract inception; however, certain pricing arrangements can provide for time-of-delivery, seasonal or market index adjustment mechanisms over time. The customer is invoiced monthly equal to the volume of energy delivered multiplied by the applicable contract rate.

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

For the three and nine months ended September 30, 2018, the Company’s energy revenue from PPA contracts with solar and wind customers was $33.2 million and $66.2 million, respectively, which does not include the market energy sales from the regulated solar and wind segment discussed below. As of September 30, 2018, the Company’s receivable balances related to PPA contracts with solar and wind customers was approximately $15.2 million. Trade receivables for PPA contracts are reflected in accounts receivable, net in the unaudited condensed 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 2018 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


18



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 (“Ri”) 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 (“Ro”) 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.

Following the acquisition of Saeta, the Company is now exposed to some concentration of credit risk given that its large Spanish portfolio has only two principal offtake contract counterparties. However, this concentration of credit risk is mitigated by the investment grade credit ratings of these offtake contract counterparties.

For the three and nine months ended September 30, 2018, regulated solar and wind revenue with customers was $94.2 million and $115.5 million, respectively. As of September 30, 2018, the Company’s receivable balance with customers from regulated solar and wind revenue was $93.8 million. The Company does not have any other significant contract asset or liability balances related to regulated solar and wind revenue.

Amortization of favorable and unfavorable rate revenue contracts, net
    
The Company accounts for its business combinations by recognizing in the financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at fair value at the acquisition date. Intangible amortization of certain revenue contracts acquired in business combinations (favorable and unfavorable rate PPAs and REC agreements) is recognized on a straight-line basis over the remaining contract term. The current period amortization for favorable rate revenue contracts is reflected as a reduction to operating revenues, net, and amortization for unfavorable rate revenue contracts is reflected as an increase to operating revenues, net. There was no impact related to the adoption of Topic 606. See Note 6. Intangibles.

Solar and wind incentive revenue
    
The Company generates incentive revenue from individual incentive agreements relating to the sale of RECs and performance-based incentives (“PBIs”) 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 as discussed in Note 2. Summary of Significant Accounting Policies. The impact of the adoption resulted in a decrease in operating revenues, net of $2.3 million and $5.3 million during the three and nine months ended September 30, 2018, respectively. Incentive revenues yet to be earned for fixed price incentive contracts are expected to be $71.3 million and recognized between 2018 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 three and nine months ended September 30, 2018, the Company’s incentive revenue from facility-linked contracts with customers was $8.8 million and $23.2 million respectively. Revenue accruals for facility linked incentive contracts within accounts receivable, net were $6.4 million as of September 30, 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


19



performance obligations for contracts for which it recognizes revenue at the amount to which it has the right to invoice for services performed.

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 unaudited condensed consolidated balance sheet. As discussed in Note 2. Summary of Significant Accounting Policies, 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 $5.0 million and $10.1 million in non-cash deferred revenue within operating revenues, net for the three and nine months ended September 30, 2018, respectively. The remaining deferred revenue balance in the unaudited condensed consolidated balance sheet as of September 30, 2018, consisted of upfront government incentives of $8.9 million and contract liabilities of $5.2 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 three and nine months ended September 30, 2018 related to contract liabilities was $0.3 million and $1.0 million, respectively.

4. ACQUISITIONS AND DISPOSITIONS

Acquisition of Saeta

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 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 $1.91 billion of project-level debt assumed. With 95.28% of the shares of Saeta acquired, the Company 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 BEP as discussed in Note 1. Basis of Presentation and Note 12. 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 8. Long-term Debt), (ii) a $359.0 million draw on the Company’s Revolver (as defined in Note 8. 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.


20




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 provisional amounts for this acquisition are subject to revision until these evaluations are completed. The preliminary allocation of the acquisition-date fair values of assets, liabilities and redeemable non-controlling interests pertaining to this business combination as of September 30, 2018, were as follows:
(In thousands)
 
Saeta
Renewable energy facilities in service
 
$
1,988,993

Accounts receivable
 
91,343

Intangible assets
 
993,274

Goodwill
 
115,084

Other assets
 
43,402

Total assets acquired
 
3,232,096

Accounts payable, accrued expenses and other current liabilities
 
93,032

Long-term debt, including current portion
 
1,906,831

Deferred income taxes
 
174,174

Asset retirement obligations
 
11,454

Derivative liabilities1
 
137,002

Other long-term liabilities
 
23,002

Total liabilities assumed
 
2,345,495

Redeemable non-controlling interests2
 
55,117

Purchase price, net of cash and restricted cash acquired3
 
$
831,484

———
(1)
Derivative liabilities are included within other long-term liabilities in the unaudited condensed 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 11. 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. The assignment of goodwill to the reporting units has not been completed. The goodwill balance is not deductible for income tax purposes.

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 unaudited condensed consolidated statements of operations for the three months ended September 30, 2018 were $107.9 million and $21.8 million, respectively, and for the nine months ended September 30, 2018 were $132.5 million and $33.4 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.


21



 
 
Saeta
 
 
Fair Value (In thousands)
 
Weighted Average Amortization Period (In years)1
Intangible assets - concessions and licenses
 
$
993,274

 
17 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 gives effect to 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 three and nine months ended September 30, 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.
 
 
Nine Months Ended September 30,
(In thousands)
 
2018
 
2017
Total operating revenues, net
 
$
740,066

 
$
749,814

Net loss
 
(108,314
)
 
(82,599
)

Acquisition Costs

Acquisition costs incurred by the Company for the three and nine months ended September 30, 2018, were $2.0 million and $14.6 million, respectively. Costs related to affiliates included in these balances were $0.3 million and $7.0 million, respectively. There were no acquisition costs incurred by the Company for the three and nine months ended 2017. These costs are reflected as acquisition-related costs and acquisition-related costs - affiliate (see Note 15. Related Parties) in the unaudited condensed 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 (“GBP”) 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 unaudited condensed consolidated statements of operations for the nine months ended September 30, 2017. The Company has retained one 11.1 MW solar project in the United Kingdom.

Residential Portfolio Sale

In the first nine months of 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 $1.1 million and $6.0 million in the second and third quarter of 2017, respectively, as a result of the sale of these companies and also disposed of $0.6 million of


22



cash and cash equivalents and $0.8 million of restricted cash in the nine months of 2017. The Company recorded an impairment charge in the fourth quarter of 2016 when it was determined that these assets met the criteria for held for sale classification, and there was no additional loss recognized during 2017 as a result of these sales.

5. RENEWABLE ENERGY FACILITIES

Renewable energy facilities, net consists of the following:
(In thousands)
 
September 30,
2018
 
December 31,
2017
Renewable energy facilities in service, at cost1
 
$
7,309,599

 
$
5,378,462

Less: accumulated depreciation - renewable energy facilities
 
(763,154
)
 
(578,474
)
Renewable energy facilities in service, net
 
6,546,445

 
4,799,988

Construction in progress - renewable energy facilities
 
9,391

 
1,937

Total renewable energy facilities, net
 
$
6,555,836

 
$
4,801,925

———
(1) The increase in renewable energy facilities is primarily due to the acquisition of Saeta. See Note 4. Acquisitions and Dispositions.

Depreciation expense related to renewable energy facilities was $79.2 million and $194.2 million for the three and nine months respectively ended September 30, 2018, as compared to $53.4 million and $160.0 million for the same periods in the prior year.

For the periods presented above, construction in progress primarily represents initial costs incurred for the construction of a new battery energy storage system for one of the Company’s wind power plants, for which construction began in the fourth quarter of 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 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 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 unaudited condensed consolidated statement of operations for the nine months ended September 30, 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.

During the third quarter of 2017, the Company sold its remaining 0.3 MW of residential assets. These assets did not meet the criteria for held for sale classification in the second quarter of 2017, but the Company determined that certain impairment indicators were present and as a result recognized an impairment charge of $1.4 million, which is reflected within impairment of renewable energy facilities in the unaudited condensed consolidated statement of operations for the nine months ended September 30, 2017.
    


23



6. INTANGIBLE ASSETS, NET AND GOODWILL

The following table presents the gross carrying amount, accumulated amortization and net book value of intangibles as of September 30, 2018:
(In thousands, except weighted average amortization period)
 
Weighted Average Amortization Period
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Book Value
Concession and licensing contracts1
 
17 years
 
$
981,333

 
$
(16,683
)
 
$
964,650

Favorable rate revenue contracts
 
14 years
 
714,678

 
(132,396
)
 
582,282

In-place value of market rate revenue contracts
 
18 years
 
535,503

 
(94,414
)
 
441,089

Favorable rate land leases
 
16 years
 
15,800

 
(2,928
)
 
12,872

Total intangible assets, net
 
 
 
$
2,247,314

 
$
(246,421
)
 
$
2,000,893

 
 
 
 
 
 
 
 
 
Unfavorable rate revenue contracts
 
7 years
 
$
33,144

 
$
(17,834
)
 
$
15,310

Unfavorable rate operations and maintenance contracts
 
1 year
 
5,000

 
(3,490
)
 
1,510

Unfavorable rate land lease
 
14 years
 
1,000

 
(204
)
 
796

Total intangible liabilities, net2
 
 
 
$
39,144

 
$
(21,528
)
 
$
17,616

    
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 operations and maintenance 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 unaudited condensed consolidated balance sheets.

Amortization expense related to concessions and licensing contracts is reflected in the unaudited condensed consolidated statements of operations within depreciation, accretion and amortization expense. During the three and nine months ended September 30, 2018, amortization expense related to concessions and licensing contracts was $13.8 million and $16.7 million, respectively. No amortization expense was recorded for the same periods in 2017.

Amortization expense related to favorable rate revenue contracts is reflected in the unaudited condensed consolidated statements of operations as a reduction of operating revenues, net. Amortization related to unfavorable rate revenue contracts is reflected in the unaudited condensed consolidated statements of operations as an increase to operating revenues, net. During the three and nine months ended September 30, 2018, net amortization expense related to favorable and unfavorable rate revenue contracts resulted in a reduction of operating revenues, net of $9.9 million and $29.5 million, respectively, as compared to a $10.0 million and $29.5 million reduction of operating revenues, net for the same periods in 2017.



24



Amortization expense related to the in-place value of market rate revenue contracts is reflected in the unaudited condensed consolidated statements of operations within depreciation, accretion and amortization expense. During the three and nine months ended September 30, 2018, amortization expense related to the in-place value of market rate revenue contracts was $4.7 million and $21.6 million, respectively, as compared to $6.4 million and $19.4 million for the same periods in the prior year.

Amortization expense related to favorable rate land leases is reflected in the unaudited condensed consolidated statements of operations within cost of operations. Amortization related to the unfavorable rate land lease and unfavorable rate operations and maintenance (“O&M”) contracts is reflected in the unaudited condensed consolidated statements of operations as a reduction of cost of operations. During the three and nine months ended September 30, 2018, net amortization related to favorable and unfavorable rate land leases and unfavorable rate O&M contracts resulted in an increase of cost of operations of $0.1 million and $0.4 million, respectively, as compared to a $0.1 million decrease and $0.4 million decrease in cost of operations for the same periods in the prior year.

See Note 4. Acquisitions and Dispositions for discussion of goodwill related to the Saeta acquisition.

7. VARIABLE INTEREST ENTITIES

The Company consolidates variable interest entities (“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 VIE were deconsolidated. No other VIEs were deconsolidated during the nine months ended September 30, 2018 and 2017.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Company’s unaudited condensed consolidated balance sheets are as follows:
(In thousands)
 
September 30,
2018
 
December 31,
2017
Current assets
 
$
124,690

 
$
142,403

Non-current assets
 
3,987,032

 
4,155,558

Total assets
 
$
4,111,722

 
$
4,297,961

Current liabilities
 
$
97,140

 
$
119,021

Non-current liabilities
 
1,055,560

 
975,839

Total liabilities
 
$
1,152,700

 
$
1,094,860


The amounts shown in the table above exclude intercompany balances that are eliminated upon consolidation. All of the assets in the table above are restricted for settlement of the VIE obligations, and all of the liabilities in the table above can only be settled by using VIE resources.


25



8. LONG-TERM DEBT
    
Long-term debt, including affiliate amounts, consists of the following: 
(In thousands, except interest rates)
 
September 30,
2018
 
December 31,
2017
 
Interest Type
 
Interest Rate (%)1
 
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
 
487,810

 
60,000

 
Variable
 
5.13
 
Revolving loan
Term Loan4
 
347,375

 
350,000

 
Variable
 
4.24
 
Term debt
Non-recourse long-term debt5:
 
 
 
 
 
 
 
 
 
 
Permanent financing
 
3,553,349

 
1,616,729

 
Blended6
 
4.837
 
Term debt / Senior notes
Financing lease obligations
 
108,560

 
115,787

 
Imputed
 
5.597
 
Financing lease obligations
Total principal due for long-term debt and financing lease obligations
 
5,997,094

 
3,642,516

 
 
 
4.907
 
 
Unamortized discount, net
 
(16,315
)
 
(19,027
)
 
 
 
 
 
 
Deferred financing costs, net
 
(26,742
)
 
(24,689
)
 
 
 
 
 
 
Less: current portion of long-term debt and financing lease obligations
 
(454,306
)
 
(403,488
)
 
 
 
 
 
 
Long-term debt and financing lease obligations, less current portion
 
$
5,499,731

 
$
3,195,312

 
 
 
 
 
 
———
(1)
As of September 30, 2018.
(2)
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 (exception for certain unencumbered non-recourse subsidiaries).
(3)
On February 6, 2018, Terra Operating LLC elected to increase the total borrowing capacity of its $450.0 million senior secured revolving credit facility (the “Revolver”), available for revolving loans and letters of credit, to $600.0 million. On October 5, 2018, Terra Operating LLC entered into an amendment to the Revolver (see Note 19. Subsequent Events). The September 30, 2018 balance includes $5.8 million drawn on an approximately $139.0 million revolving credit facility obtained by Saeta, as well as other credit facilities of Saeta. On October 26, 2018, Saeta repaid the outstanding balance under its revolving credit facility and terminated such facility.
(4)
On May 11, 2018, the Company signed a repricing amendment whereby the interest rate on the Term Loan was reduced by 0.75% per annum.
(5)
Non-recourse debt represents debt issued by subsidiaries with no recourse to TerraForm Power, Terra LLC, Terra Operating LLC or guarantors of the Company’s corporate-level debt, 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, TerraForm Power 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 of the Company’s corporate-level debt.
(6)
Includes fixed rate debt and variable rate debt. As of September 30, 2018, 44% of this balance had a fixed interest rate and the remaining 56% of this balance had a variable interest rate. The Company entered into interest rate swap agreements to fix the interest rates of a majority of the variable rate permanent financing non-recourse debt (see Note 10. Derivatives).
(7)
Represents the weighted average interest rate as of September 30, 2018.

Non-recourse Debt Defaults

As of September 30, 2018 and December 31, 2017, the Company reclassified $193.9 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 unaudited condensed 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


26



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. There were no corresponding interest rate swap reclassifications needed as a result of these remaining defaults.

Non-recourse Project 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 fund a portion of 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.

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 Euro of notes secured by 48 MW of utility-scale wind power plants located in Spain. The new notes consist of 30.0 million Euro 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 closing date) maturing in 12.5 years. Tranche A bears interest at a rate per annum equals to six-month 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.

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. The interest rates applicable to this assumed indebtedness ranged between 1.11% and 6.01% as of September 30, 2018. As of September 30, 2018, all required change of control consents in respect of this indebtedness were received by the Company.

Brookfield Sponsor Line

On October 16, 2017, TerraForm Power entered into a credit agreement with Brookfield and one of its affiliates as lenders that established a $500.0 million secured revolving credit facility (the “Sponsor Line”) 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 agreement (subject to acceleration for certain specified events). The Company may only use the Sponsor Line to fund all or a portion of certain funded acquisitions or growth capital expenditures. During the nine months ended September 30, 2018, the Company drew $86.0 million primarily to fund the Saeta acquisition, under the Sponsor Line, which the Company repaid.


27



Maturities

The aggregate contractual principal payments of long-term debt due after September 30, 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)
Remainder of 2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Total
Maturities of long-term debt1
$
90,947

 
$
257,488

 
$
256,380

 
$
259,267

 
$
751,624

 
$
4,381,388

 
$
5,997,094

———
(1)
Represents the contractual principal payment due dates for the Company’s long-term debt and does not reflect the reclassification of $193.9 million of long-term debt to current as a result of debt defaults under certain of the Company’s non-recourse financing arrangements.

9. INCOME TAXES

The income tax provision consisted of the following:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In thousands, except effective tax rate)
 
2018
 
2017
 
2018
 
2017
Loss before income tax expense (benefit)
 
$
(13,038
)
 
$
(37,453
)
 
$
(113,559
)
 
$
(96,755
)
Income tax expense (benefit)
 
6,013

 
(1,099
)
 
9,417

 
(2,256
)
Effective tax rate
 
(46.1
)%
 
2.9
%
 
(8.3
)%
 
2.3
%

As of September 30, 2017, TerraForm Power owned 65.8% of Terra LLC and consolidated the results of Terra LLC through its controlling interest. The Company recorded SunEdison’s 34.2% ownership of Terra LLC as a non-controlling interest in the financial statements. Terra LLC is treated as a partnership for income tax purposes. As such, for the nine months ended September 30, 2017, the Company recorded income tax on its 65.8% of Terra LLC’s taxable income and SunEdison recorded income tax on its 34.2% share of Terra LLC’s taxable income. On October 16, 2017, pursuant to the settlement agreement the Company entered into with SunEdison on March 6, 2017 (the “Settlement Agreement”), SunEdison transferred its interest in Terra LLC to TerraForm Power. As a result, TerraForm Power now owns 100% of the capital and profits interest in Terra LLC, except for the incentive distribution rights (“IDRs”) which are owned by BRE Delaware, Inc. (the “Brookfield IDR Holder”), an indirect wholly-owned subsidiary of Brookfield, and the Company recorded income tax on its 100% share of Terra LLC’s taxable income for the nine months ended September 30, 2018.

For the three and nine months ended September 30, 2018 and 2017, the overall effective tax rate was different than the statutory rate of 21% and 35% in 2018 and 2017, respectively, primarily due to the recording of a valuation allowance on certain tax benefits attributed to the Company, loss allocated to non-controlling interests and the effect of foreign and state taxes. As of September 30, 2018, most jurisdictions were in a gross deferred tax asset position, prior to recording any valuation allowance, except for Spain, Portugal and Uruguay (see Note 4. Acquisitions and Dispositions for deferred tax liabilities assumed in connection with the acquisition of Saeta). A valuation allowance is recorded against certain deferred tax assets in the U.S. (except for one portfolio), Chile and certain other jurisdictions, primarily because of the history of losses in those jurisdictions. The recognition of an income tax expense of $6.0 million and $9.4 million for the three and nine months ended September 30, 2018, respectively, was mostly driven by the income generated from the profits of Saeta in Spain and Uruguay and one of the Company’s portfolios in the U.S. As of September 30, 2018, the Company had not identified any uncertain tax positions for which a liability was required.

Due to the enactment of the Tax Act on December 22, 2017, the U.S. federal corporate income tax rate was reduced from 35% to 21%, effective January 1, 2018. As a result, the Company performed a preliminary analysis to revalue its deferred income taxes and included a net reduction in deferred liabilities of $5 million as of December 31, 2017. While the Company continues to believe that the provisional Tax Act adjustments are reasonable estimates of the effects on its existing deferred taxes, additional analysis and detailed reviews are still being performed to finalize the accounting for the re-measurement of deferred tax assets and liabilities as a result of the enactment of the Tax Act.


28



10. 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. 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 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 economically hedge price variability inherent in electricity sales arrangements. The objectives of the commodity contracts are to minimize the impact of variability in spot electricity prices and stabilize estimated revenue streams. The Company does not use derivative instruments for speculative purposes.

As of September 30, 2018 and December 31, 2017, fair values of the following derivative instruments were included in the 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 September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid expenses and other current assets
 
$
1,670

 
$
—

 
$
1,228

 
$
—

 
$
1,781

 
$
12,092

 
$
16,771

 
$
(58
)
 
$
16,713

Other assets
 
13,878

 
—

 
40,579

 
29

 
594

 
47,520

 
102,600

 
(248
)
 
102,352

Total assets
 
$
15,548

 
$
—

 
$
41,807

 
$
29

 
$
2,375

 
$
59,612

 
$
119,371

 
$
(306
)
 
$
119,065

Accounts payable, accrued expenses and other current liabilities
 
$
456

 
$
43

 
$
—

 
$
37,786

 
$
—

 
$
—

 
$
38,285

 
$
(58
)
 
$
38,227

Other long-term liabilities
 
1,279

 
417

 
—

 
82,616

 
46

 
—

 
84,358

 
(248
)
 
84,110

Total liabilities
 
$
1,735

 
$
460

 
$
—

 
$
120,402

 
$
46

 
$
—

 
$
122,643

 
$
(306
)
 
$
122,337

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

Accounts payable, accrued expenses and other current liabilities
 
$
2,490

 
$
—

 
$
—

 
$
197

 
$
99

 
$
—

 
$
2,786

 
$
(63
)
 
$
2,723

Other long-term 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 agreements.


As of September 30, 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 September 30, 2018 and December 31, 2017 related to the Company’s derivative transactions.



29






As of September 30, 2018 and December 31, 2017, notional amounts for derivative instruments consisted of the following:
 
 
Notional Amount as of
(In thousands)
 
September 30, 2018
 
December 31, 2017
Derivatives designated as hedging instruments:
 
 
 
 
Interest rate swaps (USD)
 
367,073

 
395,986

Interest rate swaps (CAD)
 
148,002

 
156,367

Foreign currency contracts (CAD)
 
72,400

 
—

Foreign currency contracts (EUR)
 
300,000

 
—

Commodity contracts (MWhs)
 
6,197

 
15,579

Derivatives not designated as hedging instruments:
 
 
 
 
Interest rate swaps (USD)
 
12,604

 
13,520

Interest rate swaps (EUR)1
 
1,061,456

 
—

Foreign currency contracts (EUR)2
 
640,200

 
—

Foreign currency contracts (CAD)
 
—

 
9,875

Commodity contracts (MWhs)
 
9,032

 
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 as of September 30, 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 as of September 30, 2018.

The Company elected to present all derivative assets and liabilities on a net basis on the balance sheet as a right to set-off exists. The Company enters into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements with its counterparties. An ISDA Master Agreement is an agreement 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 September 30, 2018 or December 31, 2017.

Gains and losses on derivatives not designated as hedging instruments for the three and nine months ended September 30, 2018 and 2017 consisted of the following:
 
 
Location of Loss (Gain) in the Statements of Operations
 
Three Months Ended September 30,
Nine Months Ended September 30,
(In thousands)
2018
 
2017
 
2018
 
2017
Interest rate swaps
 
Interest expense, net
 
$
4,737

 
$
27

 
$
(3,252
)
 
$
3,219

Foreign currency contracts
 
(Gain) loss on foreign currency exchange, net
 
(4,348
)
 
457

 
(16,914
)
 
1,017

Commodity contracts
 
Operating revenues, net
 
(3,880
)
 
(1,371
)
 
(21,374
)
 
(7,062
)
    
During the second quarter of 2018, the Company discontinued hedge accounting for certain long-dated commodity contracts as they were 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 derivative contracts to have intrinsic value and thus negatively impacting the effectiveness of the intrinsic value being hedged. Hedge accounting was prospectively discontinued effective April 1, 2018, with changes in fair value recorded in earnings. The gains in AOCI as of March 31, 2018, which amounted to $44.3 million, are currently being amortized through earnings over the term of these contracts, the last of which expires in 2023. The balance of the accumulated gains deferred in AOCI as of September 30, 2018, was $40.6 million. During the three and nine months ended September 30, 2018, the total gains related to these commodity contracts were $6.6 million and $31.4 million, respectively, recorded in the


30



unaudited condensed consolidated statement of operations within operating revenue, net, as compared to $4.1 million and $15.3 million for the same periods in the prior year.

Gains and losses recognized related to interest rate swaps, foreign currency contracts and commodity contracts designated as hedging instruments for the three and nine months ended September 30, 2018 and 2017 consisted of the following:
 
 
Three Months Ended September 30,
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
 
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 Earnings2
(In thousands)
 
2018
 
2017
 
2018
 
2017
 
 
2018
 
2017
 
2018
 
2017
Interest rate swaps
 
$
4,107

 
$
1,353

 
$
—

 
$
—

 
Interest expense, net
 
$
263

 
$
519

 
$
—

 
$
(315
)
Foreign currency contracts
 
3,549

 
—

 
—

 
—

 
Gain on foreign currency exchange, net
 
—

 
—

 
—

 
—

Commodity contracts
 
4,645

 
15,985

 
—

 
—

 
Operating revenues, net
 
(5,019
)
 
(425
)
 
(251
)
 
(5,316
)
Total
 
$
12,301

 
$
17,338

 
$
—

 
$
—

 
 
 
$
(4,756
)
 
$
94

 
$
(251
)
 
$
(5,631
)
————
(1)
Net of tax benefit of zero and $0.3 million attributed to interest rate swaps during the three months ended September 30, 2018 and 2017, respectively. Net of tax benefit of zero and $0.8 million attributed to commodity contracts during the three months ended September 30, 2018 and 2017, respectively.
(2)
As a result of the adoption of ASU No. 2017-12 effective January 1, 2018 (see Note 2. Summary of Significant Accounting Policies), certain gains and losses were excluded from the assessment of effectiveness that are being amortized through earnings for the three months ended September 30, 2018. No such amounts existed for the three months ended September 30, 2017 prior to the adoption of ASU No. 2017-12.
(3)
Net of tax benefit of zero and $0.7 million attributed to interest rate swaps during the three months ended September 30, 2018 and 2017, respectively. Net of tax expense of zero and $0.7 million attributed to commodity contracts during the three months ended September 30, 2018 and 2017, respectively.
 
 
Nine Months Ended September 30,
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
 
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 Earnings2
(In thousands)
 
2018
 
2017
 
2018
 
2017
 
 
2018
 
2017
 
2018
 
2017
Interest rate swaps
 
$
14,627

 
$
(1,899
)
 
—

 
$
—

 
Interest expense, net
 
$
1,236

 
$
3,163

 
$
—

 
$
(963
)
Foreign currency contracts
 
3,549

 
—

 
—

 
—

 
Gain on foreign currency exchange, net
 
—

 
—

 
—

 
—

Commodity contracts
 
(2,834
)
 
29,859

 
735

 
—

 
Operating revenues, net
 
(7,061
)
 
(3,690
)
 
(930
)
 
(5,340
)
Total
 
$
15,342

 
$
27,960

 
$
735

 
$
—

 
 
 
$
(5,825
)
 
$
(527
)
 
$
(930
)
 
$
(6,303
)
————
(1)
Net of tax benefit of zero and $0.2 million attributed to interest rate swaps during the nine months ended September 30, 2018 and 2017, respectively. Net of tax expense of zero and $2.9 million attributed to commodity contracts during the nine months ended September 30, 2018 and 2017, respectively.
(2)
As a result of the adoption of ASU No. 2017-12 effective January 1, 2018 (see Note 2. Summary of Significant Accounting Policies), certain gains and losses were excluded from the assessment of effectiveness that are being amortized through earnings for the nine months ended September 30, 2018. No such amounts existed for the nine months ended September 30, 2017 prior to the adoption of ASU No. 2017-12.
(3)
Net of tax benefit of zero and $2.4 million attributed to interest rate swaps during the nine months ended September 30, 2018 and 2017, respectively. Net of tax expense of zero and $2.8 million attributed to commodity contracts during the nine months ended September 30, 2018 and 2017, respectively.



31



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 unaudited condensed consolidated statement of stockholders’ equity for the nine months ended September 30, 2018.

Derivatives Designated as Hedging Instruments

Interest Rate Swaps

The Company has interest rate swap agreements to hedge variable rate non-recourse debt. These interest rate swaps were designated as hedging instruments and qualify for hedge accounting. Under the interest rate swap agreements, the renewable energy facilities pay a fixed rate and the counterparties to the agreements pay a variable interest rate. The amounts deferred in AOCI and reclassified into earnings during the three and nine months ended September 30, 2018 and 2017 related to these interest rate swaps are provided in the tables above. The loss expected to be reclassified into earnings over the next twelve months is approximately $2.0 million. The maximum term of outstanding interest rate swaps designated as hedging instruments is 16 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 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 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 unaudited consolidated condensed statements of cash flows.

As of September 30, 2018, the total notional amount of foreign currency forward contracts designated as net investment hedges was 300 million Euros and approximately 72.4 million Canadian dollars. The maturity dates of these derivative instruments designated as net investment hedges range from three months to two years.

Commodity Contracts

The Company has 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. These commodity contracts qualify for hedge accounting and are designated as cash flow hedges. Accordingly, the effective portions of the change in fair value of these derivatives are reported in AOCI and subsequently reclassified to earnings in the periods when the hedged transactions affect earnings. Prior to adoption of ASU 2017-12, any ineffective portions of the derivatives’ change in fair value were recognized in earnings. The amounts deferred in AOCI and reclassified into earnings during the three and nine months ended September 30, 2018 and 2017 related to these commodity contracts are provided in the tables above. The gain expected to be reclassified into earnings over the next twelve months is approximately $1.8 million. The maximum term of outstanding commodity contracts designated as hedges 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 unaudited condensed consolidated statements of operations as these hedges are not accounted for under hedge accounting.

Foreign Currency Forward Contracts

The Company enters into foreign currency forward 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 hedges are not accounted for under hedge accounting, the changes in fair value are recorded in gain on foreign currency exchange, net in the


32



unaudited condensed consolidated statements of operations.

Commodity Contracts

The Company enters into 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 hedges are not accounted for under hedge accounting, the changes in fair value are recorded in operating revenues net, in the unaudited condensed consolidated statements of operations.

11. 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 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 and 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 unaudited condensed consolidated balance sheets:
(In thousands)
As of September 30, 2018
 
As of December 31, 2017
Assets
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Interest rate swaps
$
—

 
$
15,576

 
$
—

 
$
15,576

 
$
—

 
$
4,686

 
$
—

 
$
4,686

Commodity contracts
—

 
17,236

 
84,184

 
101,420

 
—

 
27,396

 
80,268

 
107,664

Foreign currency contracts
—

 
2,069

 
—

 
2,069

 
—

 
—

 
—

 
—

Total derivative assets
$
—

 
$
34,881

 
$
84,184

 
$
119,065

 
$
—

 
$
32,082

 
$
80,268

 
$
112,350

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
122,137

 
$
—

 
$
122,137

 
$
—

 
$
7,887

 
$
—

 
$
7,887

Commodity contracts
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Foreign currency contracts
—

 
200

 
—

 
200

 
—

 
36

 
—

 
36

Total derivative liabilities
$
—

 
$
122,337

 
$
—

 
$
122,337

 
$
—

 
$
7,923

 
$
—

 
$
7,923


The Company's interest rate swaps, commodity contracts not designated as hedges and foreign currency contracts are considered Level 2, since all significant inputs are corroborated by market observable data. The Company's commodity contracts designated as hedges 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 three and nine months ended September 30, 2018 and 2017.


33



    
The following table reconciles the changes in the fair value of derivative instruments classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2018 and 2017:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In thousands)
2018
 
2017
 
2018
 
2017
Beginning balance
$
81,859

 
$
76,790

 
$
80,268

 
$
66,138

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
Included in other comprehensive income (loss)
418

 
15,601

 
(10,090
)
 
26,229

Included in operating revenues, net
1,324

 
6,407

 
16,873

 
11,831

Settlements
583

 
(1,090
)
 
(2,867
)
 
(6,490
)
Balance as of September 30
$
84,184

 
$
97,708

 
$
84,184

 
$
97,708


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 September 30, 2018 are as follows:
(In thousands, except range)
 
Fair Value as of
September 30, 2018
 
 
 
 
 
 
 
 
Transaction Type
 
Assets
 
Liabilities
 
Valuation Technique
 
Unobservable Inputs
 
Range
Commodity contracts - power
 
$
84,184

 
$
—

 
Discounted cash flow
 
Forward price (per MWh)
 
$10.4
-
$145.7
 
 
 
 
 
 
Option model
 
Volatilities
 
3.4%
-
9.8%

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 September 30, 2018 and December 31, 2017 is as follows:
 
 
As of September 30, 2018
 
As of December 31, 2017
(In thousands)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt
 
$
5,954,082

 
$
6,052,908

 
$
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 classified as Level 2 and a discounted cash flow approach using market rates for similar debt instruments. The fair value of the corporate-level senior notes is based on market price information which is classified as a Level 1 input. They are measured using the last available trades at the end of each respective fiscal year. The fair value of the Senior Notes due 2023, Senior Notes due 2025 and Senior Notes due 2028 were 98.00%, 106.25% and 93.49% of face value as of September 30, 2018, respectively, and 99.50%, 109.50% and 99.38% of face value as of December 31, 2017, respectively.
    


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12. STOCKHOLDERS’ EQUITY

The following table reflects the changes in TerraForm Power’s Class A common shares outstanding during the nine months ended September 30, 2018 and 2017:
 
 
Nine Months Ended September 30,
 
 
2018
 
2017
Balance as of January 1
 
148,086,027

 
92,223,089

Issuance of Class A common stock to affiliates
 
61,055,693

 
—

Net shares issued under equity incentive plan
 
—

 
185,507

Balance as of September 30
 
209,141,720

 
92,408,596


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 BEP (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 TerraForm Power’s Class A shares by the Purchasers was made in accordance with the support agreement that the Company entered into with Brookfield, dated February 6, 2018, and amended on May 28, 2018, pursuant to which Brookfield agreed to backstop a share offering of TerraForm Power’s Class A common stock in an amount up to $650.0 million and at a price of $10.66 per share

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, Inc. reimbursed to the Company pursuant to the insurance allocation arrangements entered into with the Company in 2017.

Stock-based Compensation

The Company has an equity incentive plan that provides for the award of incentive and nonqualified stock options, restricted stock awards (“RSAs”) and restricted stock units (“RSUs”) to personnel and directors who provide services to the Company. The maximum contractual term of an award is ten years from the date of grant. As of September 30, 2018, an aggregate of 3,822,821 shares of Class A common stock were available for issuance under this plan. Upon exercise of stock options or the vesting of RSUs, the Company will issue shares that have been previously authorized to be issued.

During the nine months ended September 30, 2018, the Company awarded 117,424 time-based RSUs to certain employees of the Company. The grant-date fair value of these awards was $1.3 million, which was calculated based on the Company's closing stock price on the date of grant, and are being recognized as compensation cost on a straight-line basis over the three year service period. The amount of stock-based compensation expense related to the equity awards in the Company's stock during the three and nine months ended September 30, 2018, was $0.1 million and $0.2 million, respectively, as compared to $1.8 million and $7.0 million for the same periods in the prior year, respectively, and is reflected in the unaudited condensed consolidated statement of operations within general and administrative expenses.

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 September 30, 2018, and changes


35



during the nine months ended September 30, 2018:
 
 
Number of RSUs Outstanding
 
Aggregate Intrinsic Value (in millions)
 
Weighted Average Remaining
Contractual Life (in years)
Balance as of January 1, 2018
 
—

 
 
 
 
Granted
 
117,424

 
 
 
 
Forfeited
 
(14,124
)
 
 
 
 
Balance as of September 30, 2018
 
103,300

 
$
1.2

 
2.5 years

Dividends

The following table presents cash dividends declared and paid on Class A common stock during the nine months ended September 30, 2018. TerraForm Power did not declare or pay a dividend during the nine months ended September 30, 2017.
 
Dividends per Share
 
Declaration Date
 
Record Date
 
Payment Date
First Quarter
$
0.19

 
February 6, 2018
 
February 28, 2018
 
March 30, 2018
Second Quarter
0.19

 
April 30, 2018
 
June 1, 2018
 
June 15, 2018
Third Quarter
0.19

 
August 13, 2018
 
September 1, 2018
 
September 15, 2018

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 of 1934. 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 September 30, 2018, no shares were repurchased under the program.

13. (LOSS) EARNINGS PER SHARE
    
Basic (loss) earnings per share is computed by dividing net (loss) income attributable to Class A common stockholders by the number of weighted average ordinary shares outstanding during the period, which is the average of shares outstanding and assumed to be outstanding, and includes contingently issuable shares as of the date when the contingent condition has been met. Diluted (loss) earnings per share is computed by adjusting basic earnings (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 include the incremental shares issuable for unvested restricted Class A common stock and contingently issuable shares in the period the contingency has been met, for the portion of the period prior to the resolution of such contingent condition.

Basic and diluted (loss) earnings per share of the Company's Class A common stock for the three and nine months ended September 30, 2018 and 2017 was calculated as follows:


36



 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In thousands, except per share amounts)
 
2018
 
2017
 
2018
 
2017
Basic and diluted (loss) earnings per share:
 
 
 
 
 
 
 
 
Net (loss) income attributable to Class A common stockholders
 
$
(33,590
)
 
$
(26,300
)
 
$
27,869

 
$
(47,491
)
Less: accretion of redeemable non-controlling interest
 
—

 
(2,316
)
 
—

 
(6,729
)
Net (loss) income attributable to Class A common stockholders after accretion of redeemable non-controlling interests
 
$
(33,590
)
 
$
(28,616
)
 
$
27,869

 
$
(54,220
)
 
 
 
 
 
 
 
 
 
Weighted average basic Class A shares outstanding
 
209,142

 
92,352

 
173,173

 
92,228

Weighted average diluted Class A shares outstanding1
 
209,142

 
92,352

 
173,186

 
92,228

 
 
 
 
 
 
 
 
 
Basic and diluted (loss) earnings per share
 
$
(0.16
)
 
$
(0.31
)
 
$
0.16

 
$
(0.59
)
———
(1)
The computation of diluted loss per share of the Company's Class A common stock for the three months ended September 30, 2018, excludes 103 thousand of potentially dilutive unvested RSUs because the effect would have been anti-dilutive. The computation of diluted earnings per share of the Company's Class A common stock for the nine months ended September 30, 2018, includes 13 thousand of RSUs considered to be dilutive and calculated using the treasury stock method. The computation of diluted loss per share of the Company's Class A common stock for the nine months ended September 30, 2017 excludes 1,228 thousand of potentially dilutive unvested RSUs because the effect would have been anti-dilutive.

14. 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 September 30, 2018, the Company had outstanding letters of credit under the Revolver of $82.5 million and outstanding project-level letters of credit of $178.4 million.

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 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.

Long-Term Service Agreement

On August 10, 2018, the Company executed an 11-year framework agreement with an affiliate of General Electric (“GE”) that, among other things, provides for the roll out, subject to receipt of third party consents, of project level, long-term service agreements (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.


37




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, SunEdison is a necessary party to this action. The plaintiffs filed an opposition to the motion to dismiss on August 22, 2016. The defendants filed their 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, and discovery is proceeding in the case. 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, Inc. 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, Inc. 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 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. The proceeding before the Department of Labor has not been dismissed.

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 September 30, 2018. However, the Company is unable to predict with certainty the ultimate resolution of these proceedings.


38




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, Inc. 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, Inc. 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 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 has not been dismissed.

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 September 30, 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 definitive merger and sponsorship transaction agreement (the “Merger Agreement”) entered into with Orion Holdings on March 6, 2017, 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,


39



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, Inc. 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.

15. RELATED PARTIES

As discussed in Note 1. Nature of Operations and Basis of Presentation, prior to the consummation of the Merger, TerraForm Power was a controlled affiliate of SunEdison, Inc. 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, held 51% of the voting securities of TerraForm Power immediately following the Merger consummation. As a result of the Merger closing, TerraForm Power is no longer a controlled affiliate of SunEdison, Inc. and became a controlled affiliate of Brookfield. Furthermore, on June 11, 2018, Orion Holdings and BEP 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 now hold approximately 65% of TerraForm Power’s Class A common stock. As discussed in Note 12. 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.

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. These include the agreements discussed below, as well as a governance agreement that established 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 a registration rights agreement that 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. In connection with the private placement of shares on June 11, 2018 discussed above, Orion Holdings, BEP and TerraForm Power entered into a joinder to the registration rights agreement and governance agreement entered into in connection with the Merger, which added BEP as a party to each respective agreement. As discussed in Note 14. Commitments and Contingencies, as part of the Merger, the Company also agreed to issue shares of Class A common stock to Orion Holdings in connection with the final resolution of certain litigation matters described above.

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 this agreement, the Company pays a base management fee on a quarterly basis, paid in arrears. Pursuant to the Brookfield MSA, the Company recorded $3.6 million and $10.5 million of charges within general and administrative expenses - affiliate in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018, 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


40



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 Company did not acquire any renewable energy facilities from Brookfield during the nine months ended September 30, 2018.

New Terra LLC Agreement

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 (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. There were no payments of IDRs made by the Company pursuant to the New Terra LLC Agreement during the nine months ended September 30, 2018, and there were no payments of IDRs made by the Company during the nine months ended September 30, 2017 pursuant to the Terra LLC agreement existing as of that time.

Lease

In May 2018, 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 arrangements with affiliates of Brookfield for a ten-year term. The Company recorded $0.2 million of charges within general and administrative expenses - affiliate in the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018, respectively.

Due from affiliate

The $0.4 million and $4.4 million due from affiliate amounts reported in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017, respectively, each represents a receivable from TerraForm Global, Inc., a controlled affiliate of Brookfield, 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 in the nine months ended September 30, 2018. There was no right of set-off with respect to these receivables from TerraForm Global, Inc. and the payables to the other Brookfield affiliates described below, and thus these amounts were separately reported in due from affiliate in the unaudited condensed consolidated balance sheet at the respective periods.

In April of 2018, the Company received $3.7 million from an affiliate of 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 condensed consolidated statement of stockholders’ equity for the nine months ended September 30, 2018.

Due to affiliates

The $10.9 million due to affiliates amount reported in the unaudited condensed consolidated balance sheet as of September 30, 2018, primarily represents payables to affiliates of Brookfield of: (i) $3.6 million for the Brookfield MSA base management fee for the third quarter of 2018; (ii) $4.0 million of acquisition-related costs for services and fees paid on behalf of the Company by affiliates of Brookfield; (iii) $1.2 million for services provided to the Company on a pass-through basis related to commodity swaps entered into by an affiliate of Brookfield on behalf of the Company; and (iv) $2.1 million for leasehold improvements, rent, office charges and other services associated with the transition to the Company’s new corporate headquarters. 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 three months of 2018, as well as $6.9 million representing the management fee for the first six months of 2018, and $1.1 million of additional Sponsor Line standby fee interest. 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 equal to 50% of the savings realized by the


41



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.

Historical SunEdison Services

As discussed above, the Company was a controlled affiliate of SunEdison, Inc. during the nine months ended September 30, 2017, and certain services were provided by SunEdison during that period. Cost of operations - affiliate was $1.2 million and $10.2 million for the three and nine months ended September 30, 2017, respectively, which represented costs incurred for O&M and asset management services that were provided to the Company by SunEdison pursuant to contractual agreements and certain project-level transition services agreements. General and administrative expenses - affiliate was $2.2 million and $6.9 million for the three and nine months ended September 30, 2017, respectively, which consisted of $0.8 million and $2.7 million of stock-based compensation expense for the respective periods that was allocated to the Company regarding equity awards in the stock of SunEdison, Inc. and TerraForm Global, Inc. (a controlled affiliate of SunEdison, Inc. at that time) that were awarded to the Company’s employees and $1.4 million and $4.2 million of costs incurred for certain management and administrative services that were provided by SunEdison during the respective periods.

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 (“EPC”), 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 unaudited condensed consolidated statement of stockholders' equity for the nine months ended September 30, 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 terminated without further liability, claims or damages on the part of the Company.

16. 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 comprise 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. 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 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. The Company’s operating segments now consist of Distributed Generation, North America Utility and International Utility that are aggregated into the Solar reportable segment, Northeast Wind, Central Wind, Hawaii Wind, Portugal Wind and Uruguay Wind operating segments that are aggregated into the Wind reportable segment, and the Regulated Spanish Solar and Wind operating segments that are aggregated within the Regulated Solar and Wind reportable segment. The operating segments have been aggregated as they have similar economic characteristics and meet all of the aggregation criteria. 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 three and nine months ended September 30, 2018 and 2017 were earned by the Company’s reportable segments from external customers in the United States (including Puerto Rico), Canada, Spain, Portugal, the United Kingdom, Uruguay and Chile.



42



The following table reflects summarized financial information concerning the Company’s reportable segments for the three and nine months ended September 30, 2018 and 2017:
 
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
(In thousands)
 
Solar
 
Wind
 
Regulated Solar and Wind
 
Corporate
 
Total
 
Solar
 
Wind
 
Corporate
 
Total
Operating revenues, net
 
$
94,883

 
$
56,963

 
$
94,196

 
$
—

 
$
246,042

 
$
107,256

 
$
46,174

 
$
—

 
$
153,430

Depreciation, accretion and amortization expense
 
28,299

 
40,992

 
33,954

 
348

 
103,593

 
27,418

 
33,937

 
475

 
61,830

Other operating costs and expenses
 
11,109

 
31,302

 
24,971

 
18,401

 
85,783

 
20,047

 
26,833

 
20,034

 
66,914

Interest expense (income), net
 
15,992

 
14,367

 
9,632

 
32,425

 
72,416

 
14,850

 
22,435

 
32,947

 
70,232

Gain on sale of renewable energy facilities
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Other non-operating (income) expenses, net
 
632

 
(347
)
 
(727
)
 
(2,270
)
 
(2,712
)
 
(854
)
 
(42
)
 
(7,197
)
 
(8,093
)
Income tax expense (benefit)1
 
749

 
927

 
2,268

 
2,069

 
6,013

 
—

 
—

 
(1,099
)
 
(1,099
)
Net income (loss)
 
$
38,102

 
$
(30,278
)
 
$
24,098

 
$
(50,973
)
 
$
(19,051
)
 
$
45,795

 
$
(36,989
)
 
$
(45,160
)
 
$
(36,354
)
———
(1)
Income tax expense (benefit) is not allocated to the Company’s segments, except for certain foreign jurisdictions.



43



 
 
Nine Months Ended September 30, 2018
 
Nine Months Ended September 30, 2017
(In thousands)
 
Solar
 
Wind
 
Regulated Solar and Wind
 
Corporate
 
Total
 
Solar
 
Wind
 
Corporate
 
Total
Operating revenues, net
 
$
237,927

 
$
200,068

 
$
115,482

 
$
—

 
$
553,477

 
$
274,742

 
$
200,190

 
$
—

 
$
474,932

Depreciation, accretion and amortization expense
 
83,041

 
113,926

 
41,148

 
1,062

 
239,177

 
82,093

 
101,992

 
1,954

 
186,039

Impairment of renewable energy facilities
 
15,240

 
—

 
—

 
—

 
15,240

 
1,429

 
—

 
—

 
1,429

Other operating costs and expenses
 
39,792

 
89,834

 
30,012

 
77,506

 
237,144

 
50,442

 
76,775

 
97,946

 
225,163

Interest expense (income), net
 
46,248

 
36,382

 
4,879

 
89,353

 
176,862

 
54,373

 
64,664

 
87,712

 
206,749

Gain on sale of renewable energy facilities
 
—

 
—

 
—

 
—

 
—

 
(37,116
)
 
—

 
—

 
(37,116
)
Other non-operating (income) expenses, net
 
(1,926
)
 
538

 
(617
)
 
618

 
(1,387
)
 
(1,768
)
 
581

 
(9,390
)
 
(10,577
)
Income tax (benefit) expense1
 
749

 
1,291

 
4,442

 
2,935

 
9,417

 
—

 
—

 
(2,256
)
 
(2,256
)
Net income (loss)
 
$
54,783

 
$
(41,903
)
 
$
35,618

 
$
(171,474
)
 
$
(122,976
)
 
$
125,289

 
$
(43,822
)
 
$
(175,966
)
 
$
(94,499
)
Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets2
 
$
2,825,855

 
$
3,236,518

 
$
3,364,310

 
$
149,294

 
$
9,575,977

 
$
2,897,036

 
$
3,400,858

 
$
89,127

 
$
6,387,021

———
(1)
Income tax expense (benefit) is not allocated to the Company’s segments, except for certain foreign jurisdictions.
(2)
Represents total assets as of September 30, 2018 and December 31, 2017, respectively.



44



17. ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables present the changes in each component of accumulated other comprehensive income (loss), net of tax:
(In thousands)
 
Foreign Currency Translation Adjustments
 
Hedging Activities1
 
Accumulated Other Comprehensive Income
Balance as of December 31, 2016
 
$
(22,133
)
 
$
45,045

 
$
22,912

Net unrealized gain arising during the period (net of zero and $5,921 tax expense, respectively)
 
12,136

 
27,960

 
40,096

Reclassification of net realized loss (gain) into earnings (net of tax benefit of $8,858 and tax expense of $400)
 
14,741

 
(527
)
 
14,214

Other comprehensive income
 
26,877

 
27,433

 
54,310

Accumulated other comprehensive income
 
4,744

 
72,478

 
77,222

Less: Other comprehensive income attributable to non-controlling interests
 
1,250

 
18,638

 
19,888

Balance as of September 30, 2017
 
$
3,494

 
$
53,840

 
$
57,334

(In thousands)
 
Foreign Currency Translation Adjustments
 
Hedging Activities1
 
Accumulated Other Comprehensive Income
Balance as of December 31, 2017
 
$
(13,412
)
 
$
61,430

 
$
48,018

Cumulative-effect adjustment (net of tax expense of $1,579)2
 
—

 
(4,164
)
 
(4,164
)
Other comprehensive (loss) income:
 
 
 
 
 
 
Net unrealized (loss) gain arising during the period (net of zero tax impact)
 
(8,229
)
 
12,528

 
4,299

Reclassification of net realized gain into earnings (net of zero tax impact)
 
—

 
(6,755
)
 
(6,755
)
Other comprehensive (loss) income
 
(8,229
)
 
5,773

 
(2,456
)
Accumulated other comprehensive (loss) income
 
(21,641
)
 
63,039

 
41,398

Less: Other comprehensive loss attributable to non-controlling interests
 
—

 
(3,038
)
 
(3,038
)
Balance as of September 30, 2018
 
$
(21,641
)
 
$
66,077

 
$
44,436

———
(1)
See Note 10. Derivatives for further breakout of hedging gains and losses between interest rate swaps, foreign currency and commodity contracts.
(2)
See Note 2. Summary of Significant Accounting Policies for discussion regarding the Company’s adoption of ASU No. 2017-12 as of January 1, 2018.




45



18. 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 unaudited condensed consolidated balance sheets. The redeemable non-controlling interests in subsidiaries balance is determined using the HLBV 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 an overstatement of the allocation of net income attributable to the redeemable non-controlling interests with a corresponding understatement 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 tables below summarize the effect of the corrections of the previously reported consolidated financial statement line items:
Condensed Consolidated Balance Sheet

 
March 31, 2018
(In thousands)
 
As Previously Reported
 
Adjustment
 
Revised
Deferred income taxes
 
$
16,839

 
$
6,282

 
$
23,121

Total liabilities
 
3,928,671

 
6,282

 
3,934,953

 
 
 
 
 
 
 
Redeemable non-controlling interests
 
50,760

 
(23,189
)
 
27,571

 
 
 
 
 
 
 
Additional paid-in capital
 
1,841,692

 
5,919

 
1,847,611

Accumulated deficit
 
(290,818
)
 
10,988

 
(279,830
)
Total TerraForm Power, Inc. stockholders’ equity
 
1,576,008

 
16,907

 
1,592,915

Total stockholders’ equity
 
2,279,350

 
16,907

 
2,296,257


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




46



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


Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
 
Three Months Ended March 31, 2018
 
Three Months Ended March 31, 2017
(In thousands, except per share amounts)
 
As Previously Reported
 
Adjustment
 
Revised
 
As Previously Reported
 
Adjustment
 
Revised
Income tax benefit
 
$
(976
)
 
$
(54
)
 
$
(1,030
)
 
$
(918
)
 
$
349

 
$
(569
)
Net loss
 
(76,367
)
 
54

 
(76,313
)
 
(56,273
)
 
(349
)
 
(56,622
)
Net (loss) income attributable to redeemable non-controlling interests
 
(2,513
)
 
491

 
(2,022
)
 
835

 
(1,828
)
 
(993
)
Net (loss) income attributable to non-controlling interests
 
(157,087
)
 
—

 
(157,087
)
 
(25,339
)
 
507

 
(24,832
)
Net income (loss) attributable to Class A common stockholders
 
83,233

 
(437
)
 
82,796

 
(31,769
)
 
972

 
(30,797
)
Earnings (loss) per share of Class A common stock - Basic and diluted
 
0.56

 
—

 
0.56

 
(0.37
)
 
0.01

 
(0.36
)
Total comprehensive loss
 
(91,104
)
 
54

 
(91,050
)
 
(39,925
)
 
(349
)
 
(40,274
)
Comprehensive loss attributable to non-controlling interests
 
(160,843
)
 
491

 
(160,352
)
 
(17,614
)
 
(1,321
)
 
(18,935
)
Comprehensive income (loss) attributable to Class A common stockholders
 
69,739

 
(437
)
 
69,302

 
(22,311
)
 
972

 
(21,339
)




47



Consolidated Statements of Operations and Comprehensive Loss
 
Three Months Ended December 31, 2017
 
Twelve Months Ended December 31, 2017
(In thousands, except per share amounts)
 
As Previously Reported
 
Adjustment
 
Revised
 
As Previously Reported
 
Adjustment
 
Revised
Income tax benefit
 
$
(18,098
)
 
$
713

 
$
(17,385
)
 
$
(23,080
)
 
$
3,439

 
$
(19,641
)
Net loss
 
(141,091
)
 
(713
)
 
(141,804
)
 
(232,864
)
 
(3,439
)
 
(236,303
)
Net loss excluding pre-acquisition net loss of renewable energy facilities acquired from SunEdison
 
(141,091
)
 
(713
)
 
(141,804
)
 
(232,864
)
 
(3,439
)
 
(236,303
)
Net (loss) income attributable to redeemable non-controlling interests
 
(7,278
)
 
(1,390
)
 
(8,668
)
 
10,884

 
(9,288
)
 
1,596

Net (loss) income attributable to non-controlling interests
 
(20,514
)
 
41

 
(20,473
)
 
(79,559
)
 
1,814


(77,745
)
Net loss attributable to Class A common stockholders
 
(113,299
)
 
636

 
(112,663
)
 
(164,189
)
 
4,035

 
(160,154
)
Loss per share of Class A common stock - Basic and diluted
 
(0.82
)
 
—

 
(0.82
)
 
(1.65
)
 
0.04

 
(1.61
)
Total comprehensive loss
 
(154,995
)
 
(713
)
 
(155,708
)
 
(192,458
)
 
(3,439
)
 
(195,897
)
Comprehensive loss attributable to non-controlling interests
 
(33,023
)
 
(1,349
)
 
(34,372
)
 
(54,018
)
 
(7,474
)
 
(61,492
)
Comprehensive loss attributable to Class A common stockholders
 
(121,972
)
 
636

 
(121,336
)
 
(138,440
)
 
4,035

 
(134,405
)
Condensed Consolidated Statements of Operations and Comprehensive Loss
 
Three Months Ended September 30, 2017
 
Nine Months Ended September 30, 2017
(In thousands, except per share amounts)
 
As Previously Reported
 
Adjustment
 
Revised
 
As Previously Reported
 
Adjustment
 
Revised
Income tax benefit
 
$
(2,633
)
 
$
1,534

 
$
(1,099
)
 
$
(4,982
)
 
$
2,726

 
$
(2,256
)
Net loss
 
(34,820
)
 
(1,534
)
 
(36,354
)
 
(91,773
)
 
(2,726
)
 
(94,499
)
Net income attributable to redeemable non-controlling interests
 
6,803

 
(1,908
)
 
4,895

 
18,162

 
(7,898
)
 
10,264

Net loss attributable to non-controlling interests
 
(15,077
)
 
128

 
(14,949
)
 
(59,045
)
 
1,773

 
(57,272
)
Net loss attributable to Class A common stockholders
 
(26,546
)
 
246

 
(26,300
)
 
(50,890
)
 
3,399

 
(47,491
)
Loss per share of Class A common stock - Basic and diluted
 
(0.31
)
 
—

 
(0.31
)
 
(0.62
)
 
0.03

 
(0.59
)
Total comprehensive loss
 
(10,853
)
 
(1,534
)
 
(12,387
)
 
(37,463
)
 
(2,726
)
 
(40,189
)
Comprehensive income (loss) attributable to non-controlling interests
 
492

 
(1,780
)
 
(1,288
)
 
(20,995
)
 
(6,125
)
 
(27,120
)
Comprehensive loss attributable to Class A common stockholders
 
(11,345
)
 
246

 
(11,099
)
 
(16,468
)
 
3,399

 
(13,069
)




48



Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
 
Three Months Ended June 30, 2017
 
Six Months Ended June 30, 2017
(In thousands, except per share amounts)
 
As Previously Reported
 
Adjustment
 
Revised
 
As Previously Reported
 
Adjustment
 
Revised
Income tax benefit
 
$
(1,431
)
 
$
843

 
$
(588
)
 
$
(2,349
)
 
$
1,192

 
$
(1,157
)
Net loss
 
(680
)
 
(843
)
 
(1,523
)
 
(56,953
)
 
(1,192
)
 
(58,145
)
Net income attributable to redeemable non-controlling interests
 
10,524

 
(4,162
)
 
6,362

 
11,359

 
(5,990
)
 
5,369

Net loss attributable to non-controlling interests
 
(18,629
)
 
1,138

 
(17,491
)
 
(43,968
)
 
1,645

 
(42,323
)
Net income (loss) attributable to Class A common stockholders
 
7,425

 
2,181

 
9,606

 
(24,344
)
 
3,153

 
(21,191
)
Earnings (loss) per share of Class A common stock - Basic and diluted
 
0.06

 
0.02

 
0.08

 
(0.31
)
 
0.03

 
(0.28
)
Total comprehensive income (loss)
 
13,315

 
(843
)
 
12,472

 
(26,610
)
 
(1,192
)
 
(27,802
)
Comprehensive loss attributable to non-controlling interests
 
(3,873
)
 
(3,024
)
 
(6,897
)
 
(21,487
)
 
(4,345
)
 
(25,832
)
Comprehensive income (loss) attributable to Class A common stockholders
 
17,188

 
2,181

 
19,369

 
(5,123
)
 
3,153

 
(1,970
)
Consolidated Statements of Operations and Comprehensive (Loss) Income
 
Twelve Months Ended December 31, 2015
 
Twelve Months Ended December 31, 2016
(In thousands, except per share amounts)
 
As Previously Reported
 
Adjustment
 
Revised
 
As Previously Reported
 
Adjustment
 
Revised
Income tax (benefit) expense
 
$
(13,241
)
 
$
657

 
$
(12,584
)
 
$
494

 
$
2,240

 
$
2,734

Net loss
 
(208,135
)
 
(657
)
 
(208,792
)
 
(241,507
)
 
(2,240
)
 
(243,747
)
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
)
Net income attributable to redeemable non-controlling interests
 
8,512

 
(2,509
)
 
6,003

 
18,365

 
(11,883
)
 
6,482

Net loss attributable to non-controlling interest
 
(138,371
)
 
798

 
(137,573
)
 
(130,025
)
 
3,307

 
(126,718
)
Net loss attributable to Class A common stockholders
 
(79,886
)
 
1,054

 
(78,832
)
 
(129,847
)
 
6,336

 
(123,511
)
Loss per share of Class A common stock - Basic and diluted
 
(1.25
)
 
0.01

 
(1.24
)
 
(1.47
)
 
0.07

 
(1.40
)
Total comprehensive loss
 
(195,005
)
 
(657
)
 
(195,662
)
 
(240,665
)
 
(2,240
)
 
(242,905
)
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
)
Comprehensive loss attributable to Class A common stockholders
 
(95,365
)
 
1,054

 
(94,311
)
 
(129,835
)
 
6,336

 
(123,499
)





49



The following table presents the activity of the redeemable non-controlling interests balance for the nine months ended September 30, 2018:
(In thousands)
 
Redeemable Non-controlling Interests
Balance as of December 31, 2017
 
$
34,660

Cumulative-effect adjustment1
 
(4,485
)
Distributions
 
(1,993
)
Net income
 
15,101

Repurchases of redeemable non-controlling interests, net
 
617

Balance as of September 30, 2018
 
$
43,900

———
(1)
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.

19. SUBSEQUENT EVENTS

Amendment to Revolving Credit Facility     

On October 5, 2018, the Company entered into a repricing amendment to the Revolver whereby the interest rate was reduced by 0.75% per annum. Borrowings under the Revolver now bear interest at a rate equal to, at the Company’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. In addition, the repricing amendment extended the maturity date of the Revolver to October 5, 2023. The Company did not incur additional debt or receive any proceeds in connection with the repricing amendment.

Fourth Quarter Dividends    

On November 8, 2018, the Board of Directors of the Company declared a fourth-quarter 2018 dividend with respect to its Class A common stock of $0.19 per share. The dividend is payable on December 17, 2018 to stockholders of record as of December 3, 2018.

Information regarding certain other subsequent events has been included within the applicable notes to the Company’s unaudited condensed consolidated financial statements.


50



Item 2. 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 related notes thereto included as part of our Annual Report on Form 10-K for the year ended December 31, 2017 and our unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2018 and other disclosures included in this Quarterly Report on Form 10-Q. References in this section to “we,” “our,” “us,” or the “Company” refer to TerraForm Power, Inc. and its consolidated subsidiaries. The results shown herein are not necessarily indicative of the results to be expected in any future period.

Overview

TerraForm Power, Inc. (“TerraForm Power” or the “Company”) owns and operates a high-quality, diversified portfolio of solar and wind assets located primarily in North America and Western Europe and underpinned by long-term contracts, totaling more than 3,600 megawatts (“MW”) of installed capacity. TerraForm Power’s goal is to acquire operating solar and wind assets in North America and Western Europe and it is sponsored by Brookfield Asset Management Inc. (“Brookfield”), a leading global alternative asset manager with over $330 billion in assets under management.

TerraForm Power’s objective is to deliver an attractive risk-adjusted return to its shareholders. 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 only material asset is an equity interest in TerraForm Power, LLC, or “Terra LLC.” TerraForm Power is the managing member of Terra LLC and operates, controls and consolidates the business affairs of Terra LLC.

Recent Developments

Information regarding recent developments appears in Item 1. Business in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, which was filed on March 7, 2018. Recent developments that have occurred subsequent to March 7, 2018 are discussed within this Item 2.

Acquisition of Saeta

On June 12, 2018, the Company completed the acquisition of the greater than 95% of the outstanding shares of Saeta Yield, S.A.U. (“Saeta”) for an aggregate consideration of $1.12 billion (the “Tendered Shares”). With greater than 90% of the shares of Saeta acquired, the Company 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, which closed on July 2, 2018. Saeta is a Spanish renewable power company with 1,028 megawatts (“MW”) of wind and solar facilities (approximately 250 MW of wind and 778 MW of solar) located primarily in Spain.

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 US Holdings 1 L.P. (“Orion Holdings”) and a subsidiary of Brookfield Renewable Partners L.P. (“BEP”) as discussed in Note 12. 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 8. Long-term Debt), (ii) a $359.0 million draw on the Company’s Revolver (as defined in Note 8. Long-term Debt), and (iii) approximately $82 million of cash on hand. The Company funded the additional purchase price of $54.6 million and certain acquisition costs with the proceeds of an additional draw on its Sponsor Line.

Long-Term Service Agreements for Wind Fleet

On August 10, 2018, the Company executed an 11-year framework agreement with GE that, among other things, provides for the roll out, subject to receipt of third party consents, of project level LTSA’s 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 LTSAs, which may include the early termination of the Company’s existing service contracts.



51



Changes within Our Portfolio

The following table provides an overview of the changes within our portfolio from December 31, 2017 through September 30, 2018:
 
Description
 
Facility Type
 
Net Nameplate Capacity (MW)1
 
 Number of Sites
 
Weighted Average Remaining Duration of PPA (Years)2

 
 
 
Total Portfolio as of December 31, 2017
 
 
 
2,606.4

 
533

 
14

 
Acquisition of Saeta
 
Solar and Wind
 
1,027.1

 
32

 
14

 
Acquisition of Integrys assets
 
Solar
 
6.1

 
6

 
11

 
Total Portfolio as of September 30, 2018
 
 
 
3,639.6

 
571

 
14

——————
(1)
Net nameplate capacity represents the maximum generating capacity at standard test conditions of a facility multiplied by the Company’s percentage of economic ownership of that facility after taking into account any redeemable preference shares and stockholder loans the Company holds. Our percentage of economic ownership is subject to change in future periods for certain facilities.
(2)
Represents weighted-average remaining term of power purchase agreements (“PPA’s”) and calculated as of December 31, 2017 and September 30, 2018, respectively.

Our Portfolio

Our current portfolio consists of renewable energy facilities located in the United States (including Puerto Rico), Spain, Portugal, Uruguay, Canada, Chile and the United Kingdom with a combined nameplate capacity of 3,639.6 MW as of September 30, 2018. These renewable energy facilities generally have long-term PPAs with creditworthy counterparties. As of September 30, 2018, on a weighted-average basis (based on MW), our PPAs had a remaining life of 14 years and our counterparties to our PPAs had an average investment grade credit rating.

The following table summarizes our portfolio as of September 30, 2018:
Description
 
Nameplate Capacity (MW)
 
Net Nameplate Capacity (MW)1
 
Number of Sites
 
Weighted Average Remaining Duration of PPA (Years)2
Solar Distributed Generation:
 
 
 
 
 
 
 
 
U.S.
 
410.1

 
401.8

 
475

 
15

Canada
 
8.5

 
8.5

 
20

 
15

Total Solar Distributed Generation
 
418.6

 
410.3

 
495

 
15

 
 
 
 
 
 
 
 
 
Solar Utility:
 
 
 
 
 
 
 
 
U.S.
 
498.6

 
498.6

 
20

 
19

Canada
 
59.4

 
59.4

 
4

 
16

U.K.
 
11.1

 
11.1

 
1

 
11

Chile
 
101.6

 
101.6

 
1

 
15

Total Solar Utility
 
670.7

 
670.7

 
26

 
18

 
 
 
 
 
 
 
 
 
Regulated Solar and Wind:
 
 
 
 
 
 
 
 
Spain
 
788.0

 
788.0

 
21

 
14

 
 
 
 
 
 
 
 
 
Wind Utility:
 
 
 
 
 
 
 
 
U.S.
 
1,536.3

 
1,453.5

 
17

 
10

Canada
 
78.0

 
78.0

 
1

 
12

Portugal
 
143.8

 
143.8

 
9

 
10

Uruguay
 
95.3

 
95.3

 
2

 
19

Total Wind Utility
 
1,853.4

 
1,770.6

 
29

 
11

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Renewable Energy Facilities
 
3,730.7

 
3,639.6

 
571

 
14

———


52



(1)
Net nameplate capacity represents the maximum generating capacity at standard test conditions of a facility multiplied by the Company’s percentage of economic ownership of that facility as of September 30, 2018, after taking into account any redeemable preference shares and stockholder loans the Company holds. Our percentage of economic ownership is subject to change in future periods for certain facilities.
(2)
Represents the weighted-average term of remaining PPA and calculated as of September 30, 2018.


Key Metrics

Operating Metrics

Net nameplate capacity

We measure the electricity-generating production capacity of our renewable energy facilities in net nameplate capacity. Rated capacity is the expected maximum output a power generation system can produce without exceeding its design limits. Net nameplate capacity is the rated capacity of all of the renewable energy facilities we own adjusted to reflect our economic ownership of joint ventures and similar power generation facilities. We measure net nameplate capacity for solar generation facilities in MW in direct current (“DC”) and for wind power plants in MW in alternating current (“AC”). The size of our renewable energy facilities varies significantly among the assets comprising our portfolio. We believe the combined net nameplate capacity of our portfolio is indicative of our overall production capacity and period to period comparisons of our net nameplate capacity are indicative of the growth rate of our business. Our renewable energy facilities had an aggregate net nameplate capacity of 3,639.6 MW as of September 30, 2018.

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 three and nine months ended September 30, 2018 were as follows:

Operating Metrics
 
Three Months Ended September 30,
 
Nine Months Ended
September 30,
(In GWh)
 
2018
 
2017
 
2018
 
2017
Solar segment
 
528

 
524

 
1,468

 
$
1,534

Wind segment
 
1,051

 
854

 
3,891

 
3,890

Regulated Solar and Wind segment
 
488

 
—

 
578

 
—

Total
 
2,067

 
1,378

 
5,937

 
5,424






53



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 unaudited condensed consolidated results of operations for the three and nine months ended September 30, 2018 compared to the same periods in the prior year:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In thousands)
 
2018
 
2017
 
2018
 
2017
Operating revenues, net
 
$
246,042

 
$
153,430

 
$
553,477

 
$
474,932

Operating costs and expenses:
 
 
 
 
 
 
 
 
Cost of operations
 
59,027

 
41,859

 
146,155

 
108,402

Cost of operations - affiliate
 
—

 
1,199

 
—

 
10,224

General and administrative expenses
 
21,334

 
21,664

 
65,483

 
99,644

General and administrative expenses - affiliate
 
3,432

 
2,192

 
10,929

 
6,893

Acquisition-related costs
 
1,655

 
—

 
7,612

 
—

Acquisition-related costs - affiliate
 
335

 
—

 
6,965

 
—

Impairment of renewable energy facilities
 
—

 
—

 
15,240

 
1,429

Depreciation, accretion and amortization expense
 
103,593

 
61,830

 
239,177

 
186,039

Total operating costs and expenses
 
189,376

 
128,744

 
491,561

 
412,631

Operating income
 
56,666

 
24,686

 
61,916

 
62,301

Other expenses (income):
 
 
 
 
 
 
 
 
Interest expense, net
 
72,416

 
70,232

 
176,862

 
206,749

Gain on sale of renewable energy facilities
 
—

 
—

 
—

 
(37,116
)
Gain on foreign currency exchange, net
 
(3,070
)
 
(1,078
)
 
(4,257
)
 
(5,695
)
Other expenses (income), net
 
358

 
(7,015
)
 
2,870

 
(4,882
)
Total other expenses, net
 
69,704

 
62,139

 
175,475

 
159,056

Loss before income tax expense (benefit)
 
(13,038
)
 
(37,453
)
 
(113,559
)
 
(96,755
)
Income tax expense (benefit)
 
6,013

 
(1,099
)
 
9,417

 
(2,256
)
Net loss
 
(19,051
)
 
(36,354
)
 
(122,976
)
 
(94,499
)
Less: Net income attributable to redeemable non-controlling interests
 
12,443

 
4,895

 
15,101

 
10,264

Less: Net income (loss) attributable to non-controlling interests
 
2,096

 
(14,949
)
 
(165,946
)
 
(57,272
)
Net (loss) income attributable to Class A common stockholders
 
$
(33,590
)
 
$
(26,300
)
 
$
27,869

 
$
(47,491
)



54



Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Operating Revenues, net
    
Operating revenues, net for the three months ended September 30, 2018 and 2017 were as follows:
 
 
Three Months Ended September 30,
 
 
(In thousands, other than MW data)
 
2018
 
2017
 
Change
Energy:
 
 
 
 
 
 
Solar
 
$
79,203

 
$
81,084

 
$
(1,881
)
Wind
 
53,620

 
42,485

 
11,135

Regulated Solar and Wind
 
79,950

 
—

 
79,950

 
 
 
 
 
 
 
Incentives, including affiliates:
 
 
 
 
 
 
Solar
 
$
15,680

 
$
26,172

 
$
(10,492
)
Wind
 
3,343

 
3,689

 
(346
)
Regulated Solar and Wind
 
14,246

 
—

 
14,246

Total operating revenues, net
 
$
246,042

 
$
153,430

 
$
92,612

 
 
 
 
 
 
 
GWh sold:
 
 
 
 
 
 
Solar
 
571

 
524

 
47

Wind
 
1,375

 
854

 
521

Regulated Solar and Wind
 
488

 
—

 
488

Total GWh sold
 
2,434

 
1,378

 
1,056

 
 
 
 
 
 
 
 
 
September 30,
 
 
 
 
2018
 
2017
 
Change
Net nameplate capacity (MW):
 
 
 
 
 
 
Solar
 
1,081

 
1,075

 
6

Wind
 
1,771

 
1,532

 
239

Regulated Solar and Wind
 
788

 
—

 
788

Total net nameplate capacity (MW)
 
3,640

 
2,607

 
1,033

    
Energy revenue for our Solar segment decreased by $1.9 million during the three months ended September 30, 2018, compared to the same period in 2017, primarily due to marginally lower resource in the Utility fleet and unfavorable price mixes in the Distributed Generation fleet versus prior year. Energy revenue for our Wind segment increased by $11.1 million, primarily driven by a $13.7 million contribution from Saeta’s operations in Portugal and Uruguay and a $3.1 million increase due to improved resource. These increases were partially offset by a $2.8 million decrease in unrealized gains on commodity contract derivatives, a $1.9 million decrease due to lower availability and a $1.0 million reduction due to lower basis pricing in Texas as a result of continued challenged market conditions. Saeta was acquired in June 2018 and contributed energy revenue of $80.0 million to the new Regulated Solar and Wind segment, which includes all of its operations in Spain.












55



Incentive revenue for our Solar segment decreased by $10.5 million during the three months ended September 30, 2018, compared to the same period in 2017, primarily driven by a (i) $5.1 million decrease due to a change in revenue recognition timing for Renewable Energy Credits (“RECs”) and a $4.5 million reduction in deferred revenue related to incentive tax credits, each as a result of our adoption of the new revenue standard, and (ii) $1.1 million reduction due to decreased REC sales to one off-taker that declared bankruptcy in the first quarter of 2018 (see Note 5. Renewable Energy Facilities). Incentive revenue for our Wind segment decreased by $0.3 million, primarily due to lower pricing in the Northeast, partially offset by the change in revenue recognition timing for REC’s resulting from our adoption of the new revenue standard. Saeta contributed incentive revenue of $14.2 million to the new Regulated Solar and Wind segment.

Costs of Operations

Costs of operations for the three months ended September 30, 2018 and 2017 were as follows:
 
 
Three Months Ended September 30,
 
 
(In thousands)
 
2018
 
2017
 
Change
Cost of operations:
 
 
 
 
 
 
Solar
 
$
9,775

 
$
17,393

 
$
(7,618
)
Wind
 
27,684

 
24,466

 
3,218

Regulated Solar and Wind
 
21,568

 
—

 
21,568

Cost of operations - affiliate:
 
 
 
 
 
 
Solar
 
—

 
691

 
(691
)
Wind
 
—

 
508

 
(508
)
Total cost of operations
 
$
59,027

 
$
43,058

 
$
15,969


Total cost of operations for the three months ended September 30, 2018 increased compared to the same period in 2017, primarily driven by a $21.6 million million contribution from Saeta’s new Regulated Solar and Wind segment. Solar segment cost of operations decreased by $7.6 million million during the three months ended September 30, 2018, compared to the same period in 2017, primarily due to reduced operations and maintenance (“O&M”) and other operating expenses of [$4.3] million in the current year. Total cost of operations for our Wind segment increased by $3.2 million as compared to the same period in 2017, primarily driven by increased costs of $3.1 million contributed by Saeta’s operations in Portugal and Uruguay.

Subsequent to the Company’s consummation of the merger (the “Merger”) with affiliates of Brookfield on October 16, 2017, the Company is no longer an affiliate of SunEdison, Inc., and in the fourth quarter of 2017, with the exception of its 101.6 MW renewable energy facility in Chile, the Company is operating independently from SunEdison as a provider of operations and maintenance and asset management services to the Company.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2018 and 2017 were as follows:
 
 
Three Months Ended September 30,
 
 
(In thousands)
 
2018
 
2017
 
Change
General and administrative expenses:
 
 
 
 
 
 
Solar
 
$
1,334

 
$
2,074

 
$
(740
)
Wind
 
3,618

 
835

 
2,783

Regulated Solar and Wind
 
3,403

 
—

 
3,403

Corporate
 
12,979

 
18,755

 
(5,776
)
Total general and administrative expenses
 
$
21,334

 
$
21,664

 
$
(330
)
General and administrative expenses - affiliate:
 
 
 
 
 
 
Corporate
 
3,432

 
2,192

 
1,240

    


56



General and administrative expenses decreased by $0.3 million during the three months ended September 30, 2018, compared to the same period in 2017. The decrease in general and administrative expenses was primarily due to lower Corporate and general and administrative expenses of $5.8 million, partially offset by the inclusion of Saeta’s Regulated Solar and Wind segment, which was acquired in June 2018, and an increase of $2.8 million in the Wind segment, primarily due to additional legal fees. The decrease in Corporate general and administrative expenses of $5.8 million was primarily driven by a $3.6 million decrease in fees for accounting and legal services as a result of litigation and transaction costs incurred in connection with the Merger in 2017 and a reduction in employee compensation of $3.7 million.

General and administrative expenses - affiliate were $3.4 million during the three months ended September 30, 2018, which primarily consisted of a $3.7 million charge for the Brookfield MSA quarterly base management fee, pursuant to which Brookfield and certain of its affiliates provide certain management and administrative services to the Company, including the provision of strategic and investment management services. General and administrative expenses - affiliate were $2.1 million during the three months ended September 30, 2017 which consisted of $0.9 million of stock-based compensation expense that was allocated to the Company for unvested equity awards held by the Company’s employees in the stock of SunEdison, Inc. and TerraForm Global, Inc. and $2.4 million of costs incurred for management and administrative services that were provided by SunEdison.

Acquisition-Related Costs

As discussed in Note 4. Acquisitions to our unaudited condensed consolidated financial statements, on June 12, 2018, the Company completed the acquisition of the Tendered Shares 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, the Company 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 incurred by the Company were $2.0 million for the three months ended September 30, 2018, which consisted of investment banker advisory fees and professional fees for legal and accounting services, as well as reimbursements to affiliates of Brookfield for amounts paid on behalf of the Company. There were no acquisition costs incurred by the Company for the three months ended September 30, 2017. These costs are reflected as acquisition and related costs and acquisition and related costs - affiliate (see Note 15. Related Parties in the unaudited condensed consolidated statements of operations) and are excluded from the unaudited pro forma net loss amount disclosed in Note 4. Acquisitions and Dispositions to our unaudited condensed consolidated financial statements.

Depreciation, Accretion and Amortization Expense

Depreciation, accretion and amortization expense increased by $41.8 million during the three months ended September 30, 2018, compared to the same period in 2017. This increase was primarily the result of the renewable energy assets acquired from Saeta.

Interest Expense, Net
 
 
Three Months Ended September 30,
 
 
(In thousands)
 
2018
 
2017
 
Change
Corporate-level
 
$
32,425

 
$
32,947

 
$
(522
)
Non-recourse:
 
 
 
 
 
 
Solar
 
15,992

 
14,850

 
1,142

Wind
 
14,367

 
22,435

 
(8,068
)
Regulated Solar and Wind
 
9,632

 
$
—

 
9,632

Total interest expense, net
 
$
72,416

 
$
70,232

 
$
2,184


Interest expense, net increased by $2.2 million during the three months ended September 30, 2018, compared to the same period in 2017, primarily driven by the inclusion of our Regulated Solar and Wind segment in 2018, partially offset by a decrease at our Wind segment. The reduction at our Wind segment is primarily due to a $9.4 million decrease resulting from the repayment of the remaining outstanding principal balance of a $300.0 million non-recourse portfolio term loan in the fourth


57



quarter of 2017. Total interest expense was reduced by a positive change of $3.6 million in the fair value of interest rate swaps acquired from Saeta during the second quarter of 2018.

Gain on Foreign Currency Exchange, net

We recognized a net gain on foreign currency exchange of $3.1 million for the three months ended September 30, 2018, primarily due to $8.1 million of realized and unrealized net gains on foreign currency contracts, which were partially offset by $5.8 million on the remeasurement of intercompany loans, the majority of which are denominated in Euro and Canadian dollars. We recognized a net gain on foreign currency exchange of $1.1 million for the three months ended September 30, 2017, primarily due to a $1.5 million unrealized gain on the remeasurement of intercompany loans, which are primarily denominated in Canadian dollars, offset by $0.4 million of realized and unrealized net losses on foreign currency derivatives.

Other Expenses (Income), net

Other expenses, net was $0.4 million for the three months ended September 30, 2018 as compared to other income, net of $7.0 million during the same period in 2017. Other income, net for the three months ended September 30, 2017 included a $5.3 million gain related to a settlement agreement with insurers of one of our wind power plants.

Income Tax Expense (Benefit)

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”), which enacted major changes to the U.S. tax code, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Income tax expense was $6.0 million for the three months ended September 30, 2018, compared to a benefit of $1.1 million during the same period in 2017. For the three months ended September 30, 2018 and 2017, the overall effective tax rate was different than the statutory rate of 21% and 35%, respectively, due to the recording of a valuation allowance on certain tax benefits attributed to the Company, loss allocated to non-controlling interests and the effect of foreign and state taxes. The recognition of income tax expense of $6.0 million for the three months ended September 30, 2018 was mostly driven by the income generated from the profits of Saeta in Spain and Uruguay and one of the Company’s U.S. portfolios.

Net Income (Loss) Attributable to Non-Controlling Interests

Net income attributable to non-controlling interests, including redeemable non-controlling interests, was $14.5 million for the three months ended September 30, 2018 and was attributable to project-level tax equity partnerships, compared to net loss attributable to non-controlling interests of $10.1 million for the three months ended September 30, 2017.


58



Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

Operating Revenues, net

Operating revenues, net for the nine months ended September 30, 2018 and 2017 were as follows:
 
 
Nine Months Ended September 30,
 
 
(In thousands, other than MW data)
 
2018
 
2017
 
Change
Energy:
 
 
 
 
 
 
Solar
 
$
187,359

 
$
189,614

 
$
(2,255
)
Wind
 
186,807

 
181,286

 
5,521

Regulated Solar and Wind
 
98,236

 
—

 
98,236

Incentives, including affiliates:
 
 
 
 
 
 
Solar
 
50,568

 
85,128

 
(34,560
)
Wind
 
13,261

 
18,904

 
(5,643
)
Regulated Solar and Wind
 
17,246

 
—

 
17,246

Total operating revenues, net
 
$
553,477

 
$
474,932

 
$
78,545

 
 
 
 
 
 
 
GWh sold:
 
 
 
 
 
 
Solar
 
1,468

 
1,534

 
(66
)
Wind
 
3,891

 
3,890

 
1

Regulated Solar and Wind
 
578

 
—

 
578

Total GWh sold
 
5,937

 
5,424

 
513

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30,
 
 
Net nameplate capacity (MW):
 
2018
 
2017
 
Change
Solar
 
1,081

 
1,075

 
6

Wind
 
1,771

 
1,532

 
239

Regulated Solar and Wind
 
788

 
—

 
788

Total net nameplate capacity (MW)
 
3,640

 
2,607

 
1,033

    
Saeta was acquired in June 2018 and contributed energy revenue of $98.2 million to the new Regulated Solar and Wind segment, which represented all of its operations in Spain. Energy revenue for our Solar segment decreased by $2.3 million during the nine months ended September 30, 2018, compared to the same period in 2017, primarily due to the absence of $7.1 million of associated with renewable energy facilities that were sold in 2017, partially offset by higher revenue of $4.8 million primarily driven by increased solar resource. Energy revenue for our Wind segment increased by $5.5 million, primarily driven by a $17.1 million contribution from Saeta’s operations in Portugal and Uruguay, $8.6 million due to improved resource, a $5.1 million increase in unrealized gains on commodity contract derivatives, and $4.0 million increase due to higher pricing. These increases in revenue were partially offset by $22.7 million lower availability primarily driven by outages at our Raleigh and Bishop Hill facilities, and due to a $7.1 million reduction due to lower basis pricing in Texas as a result of continued challenged market conditions. 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.
 


59



Incentive revenue for our Solar segment decreased by $34.6 million during the nine months ended September 30, 2018, compared to the same period in 2017, primarily due to a $16.1 million decrease in REC revenue recognition, a $7.6 million reduction resulting from the sale of renewable energy facilities in the second quarter of 2017, a $6.4 million decrease in deferred revenue related to the upfront sale of investment tax credits to non-controlling interests, as a result of our adoption of the new revenue standard and a $2.0 million reduction due to decreased REC sales to one off-taker that declared bankruptcy in the first quarter of 2018 (see Note 5. Renewable Energy Facilities). Incentive revenue for our Wind segment decreased by $5.6 million primarily due to the change in revenue recognition timing for RECs resulting from the adoption of the new revenue standard in 2018. Saeta contributed Incentive revenue of $17.2 million in the Regulated Solar and Wind segment from the date of acquisition.

Costs of Operations

Costs of operations for the nine months ended September 30, 2018 and 2017 were as follows:
 
 
Nine Months Ended September 30,
 
 
(In thousands)
 
2018
 
2017
 
Change
Cost of operations:
 
 
 
 
 
 
Solar
 
$
36,259

 
$
37,098

 
$
(839
)
Wind
 
83,963

 
71,304

 
12,659

Regulated Solar and Wind
 
25,933

 
—

 
25,933

Cost of operations - affiliate:
 
 
 
 
 
 
Solar
 
—

 
7,285

 
(7,285
)
Wind
 
—

 
2,939

 
(2,939
)
Total cost of operations
 
$
146,155

 
$
118,626

 
$
27,529


Total cost of operations for our Solar segment decreased by $0.8 million during the nine months ended September 30, 2018, compared to the same period in 2017, primarily due to lower O&M expenses and other operating costs in 2018. Total cost of operations for our Wind segment increased by $12.7 million compared to the same period in 2017, primarily driven by the increased disposals of property and equipment of $6.0 million at one of our Hawaii wind and Raleigh projects as well as higher decommissioning costs, and increased costs of $3.2 million contributed by Saeta’s operations in Portugal and Uruguay. Saeta also contributed $25.9 million to the new Regulated Solar and Wind segment, which includes all of its operations in Spain.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2018 and 2017 were as follows:
 
 
Nine Months Ended September 30,
 
 
(In thousands)
 
2018
 
2017
 
Change
General and administrative expenses:
 
 
 
 
 
 
Solar
 
$
3,533

 
$
7,112

 
$
(3,579
)
Wind
 
5,871

 
1,913

 
3,958

Regulated Solar and Wind
 
4,079

 
—

 
4,079

Corporate
 
52,000

 
90,619

 
(38,619
)
Total general and administrative expenses
 
$
65,483

 
$
99,644

 
$
(34,161
)
General and administrative expenses - affiliate:
 
 
 
 
 
 
Corporate
 
$
10,929

 
$
6,893

 
$
4,036


General and administrative expenses decreased by $34.2 million during the nine months ended September 30, 2018, compared to the same period in 2017, primarily driven by a $38.6 million decrease in Corporate general and administrative expenses. The decrease in Corporate general and administrative expenses is primarily due to a $24.8 million decrease in professional fees for legal, accounting and advisory services and a $12.1 million decrease in employee compensation costs. The decrease in professional fees was primarily driven by (i) $13.8 million decrease for accounting services primarily due to


60



AlixPartners, LLP fees incurred for the former interim Chief Accounting Officer and Chief Operating Officer support in 2017; (ii) $10.3 million decrease for legal services as a result of litigation and transaction costs incurred in connection with the Merger in 2017; and (iii) $4.9 million decrease in investment banker advisory fees associated with the Merger in 2017. The reduction in employee compensation was driven by $5.1 million decrease in stock-based compensation expense due to the accelerated vesting of all previously unvested restricted stock units triggered by the change in control upon the consummation of the Merger on October 16, 2017 and a $1.1 million decrease in salaries and benefits costs due to a reduction of employee headcount, partially offset by a $2.7 million increase for severance and transition bonus costs incurred in 2018 as a result of the Company's restructuring plan subsequent to the Merger.

General and administrative expenses - affiliate were $10.9 million during the nine months ended September 30, 2018, which primarily consisted of a $10.5 million charge for the Brookfield MSA quarterly base management fee, pursuant to which Brookfield and certain of its affiliates provide certain management and administrative services to the Company, including the provision of strategic and investment management services. General and administrative expenses - affiliate were $6.9 million during the nine months ended September 30, 2017, which consisted of $2.7 million of stock-based compensation expense that was allocated to the Company for unvested equity awards held by the Company’s employees in the stock of SunEdison, Inc. and TerraForm Global, Inc. and $2.8 million of costs incurred for management and administrative services that were provided by SunEdison.
    
Acquisition-Related Costs
    
As discussed in Note 4. Acquisitions to our unaudited condensed consolidated financial statements, on June 12, 2018, the Company completed the acquisition of the Tendered Shares for total aggregate consideration of $1.12 billion. With greater than 90% of the shares of Saeta acquired, the Company 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.

Acquisition costs incurred by the Company were $14.6 million for the nine months ended September 30, 2018, which consisted of investment banker advisory fees and professional fees for legal and accounting services. Costs related to affiliates included in this balance were $7.0 million and included reimbursements to affiliates of Brookfield for fees and expenses incurred on behalf of the Company. There were no acquisition costs incurred by the Company for the nine months ended September 30, 2017. These costs are reflected as acquisition and related costs and acquisition and related costs - affiliate (see Note 15. Related Parties to our unaudited condensed consolidated financial statements) in the unaudited condensed consolidated statements of operations and are excluded from the unaudited pro forma net loss amount disclosed above.

Impairment of Renewable Energy Facilities

We had a REC sales agreement with a customer expiring December 31, 2021 that was 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 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 equal to the difference between the carrying amount and the estimated fair value for the nine months ended September 30, 2018.

The Company sold its remaining 0.3 MW of residential assets during the second quarter of 2017. Prior to the sale, 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 unaudited condensed consolidated statement of operations for the nine months ended September 30, 2017.

Depreciation, Accretion and Amortization Expense

Depreciation, accretion and amortization expense increased by $53.1 million during the nine months ended September 30, 2018, compared to the same period in 2017. This increase was primarily the result of the acquisition of renewable energy assets from Saeta and capital additions placed in service 2018.



61




Interest Expense, Net

Interest expense, net for the nine months ended September 30, 2018 and 2017 were as follows:
 
 
Nine Months Ended September 30,
 
 
(In thousands)
 
2018
 
2017
 
Change
Corporate-level
 
$
89,353

 
$
87,712

 
$
1,641

Non-recourse:
 
 
 
 
 
 
Solar
 
46,248

 
54,373

 
(8,125
)
Wind
 
36,382

 
64,664

 
(28,282
)
Regulated Solar and Wind
 
4,879

 
—

 
4,879

Total interest expense, net
 
$
176,862

 
$
206,749

 
$
(29,887
)

Interest expense, net decreased by $29.9 million during the nine months ended September 30, 2018, compared to the same period in 2017, primarily driven by a decrease at our Solar and Wind segments. The decrease at our Solar segment is primarily as a result of the sale of substantially all of our solar power plants located in the U.K. in May of 2017. The decrease in interest expense our Wind segment was primarily due to a decrease resulting from the repayment of the remaining outstanding principal balance of a $300.0 million non-recourse portfolio term loan in the fourth quarter of 2017. Total interest expense was partially offset by $4.8 million in the Regulated Solar and Wind segment which included a positive change of $11.2 million in the fair value of interest rate swaps acquired from Saeta during the first half of 2018.

Gain on Sale of Renewable Energy Facilities

As discussed in Note 2. Assets Held for Sale to our unaudited condensed consolidated financial statements, on May 11, 2017, the Company 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. The Company recognized a gain on the sale of $37.1 million within gain on sale of renewable energy facilities in the unaudited condensed consolidated statement of operations for the nine months ended September 30, 2017. The Company has retained 11.1 MW of solar assets in the U.K.

Gain on Foreign Currency Exchange, net

We recognized a net gain on foreign currency exchange of $4.3 million for the nine months ended September 30, 2018, primarily due to a total $16.8 million net realized and unrealized gain on foreign currency derivative contracts that were partially offset by a loss of $13.5 million on the remeasurement of intercompany loans, which are primarily denominated in Euro. We recognized a net gain on foreign currency exchange of $5.7 million for the nine months ended September 30, 2017, driven by a $6.7 million unrealized gain on the remeasurement of intercompany loans, which were primarily denominated in Canadian pounds, partially offset by $1.0 million of realized and unrealized net losses on foreign currency derivatives.

Other Expenses (Income), net

Other expenses, net was $2.9 million for the nine months ended September 30, 2018 and included a loss of $1.5 million representing deferred financing costs written off as a result of refinancing the Company’s Term Loan. Other income, net was $4.9 million for the nine months ended September 30, 2017 and primarily related to a settlement agreement with insurers of one of our wind power plants.

Income Tax Expense (Benefit)

Income tax expense was $9.4 million for the nine months ended September 30, 2018, compared to a benefit of $2.3 million during the same period in 2017. For the nine months ended September 30, 2018 and 2017, the overall effective tax rate was different than the statutory rate of 21% and 35%, respectively, due to the recording of a valuation allowance on certain tax benefits attributed to the Company, loss allocated to non-controlling interests and the effect of foreign and state taxes. The recognition of an income tax expense of $9.4 million for the nine months ended September 30, 2018, was mostly driven by the income generated from the profits of Saeta in Spain and Uruguay and one of the Company’s U.S. portfolios.


62




Net Income (Loss) Attributable to Non-Controlling Interests

Net loss attributable to non-controlling interests, including redeemable non-controlling interests, was $150.8 million for the nine months ended September 30, 2018, and was attributable to project-level tax equity partnerships, compared to $47.0 million for the nine months ended September 30, 2017. The increase is primarily due to the reduction in the tax rate used in the HLBV methodology applied by the Company and described in Note 2. Summary of Significant Accounting Policies. 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.

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 September 30, 2018 and December 31, 2017:
(In thousands)
 
September 30,
2018
 
December 31, 2017
Revolving Credit Facilities1
 
$
487,810

 
$
60,000

Senior Notes2
 
1,500,000

 
1,500,000

Term Loan3
 
347,375

 
350,000

Non-recourse long-term debt, including current portion4
 
3,661,909

 
1,732,516

Long-term indebtedness, including current portion5
 
$
5,997,094

 
$
3,642,516

Total stockholders’ equity and redeemable non-controlling interests
 
2,856,988

 
2,428,708

Total capitalization
 
$
8,854,082

 
$
6,071,224

Debt to total capitalization
 
68
%
 
60
%
———
(1)
Represents $482.0 million drawn under on our senior secured corporate revolving credit facility (the “Revolver”) and $5.8 million drawn under Saeta’s approximately $139.0 million revolving credit facilities. On October 5, 2018, Terra Operating LLC entered into an amendment to the Revolver. See Note 19. Subsequent Events to our unaudited condensed consolidated financial statements. On October 26, 2018, Saeta repaid the outstanding balance under its revolver and terminated such revolving credit facility.
(2)
Represents corporate senior notes.
(3)
Represents senior secured term loan facility.
(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 $43.1 million and $43.7 million of unamortized debt discounts and deferred financing costs as of September 30, 2018 and December 31, 2017, respectively.

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 as discussed and defined below), debt capacity at our projects, non-core asset sales and proceeds from the issuance of equity securities through public markets.



63



The following table summarizes corporate liquidity and available capital as of September 30, 2018 and December 31, 2017:
(In thousands)
 
September 30, 2018
 
December 31, 2017
Unrestricted corporate cash
 
$
110,683

 
$
46,810

Project-level distributable cash
 
38,356

 
21,180

Cash available to corporate
 
149,039

 
67,990

Credit facilities:
 
 
 
 
Committed revolving credit facilities1
 
739,000

 
450,000

Drawn portion of revolving credit facilities
 
(487,810
)
 
(60,000
)
Revolving line of credit commitments
 
(82,500
)
 
(102,637
)
Undrawn portion of Sponsor Line2
 
500,000

 
500,000

Available portion of credit facilities
 
668,690

 
787,363

Corporate liquidity
 
$
817,729

 
$
855,353

Other project-level unrestricted cash
 
200,524

 
60,097

Project-level restricted cash3
 
160,432

 
96,700

Project-level credit commitments
 
178,407

 
2,800

Available capital
 
$
1,357,092

 
$
1,014,950

———
(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 below.
(2)
Represents a $500.0 million secured revolving credit facility we entered into pursuant to a credit agreement (the “Sponsor Line”) with Brookfield and one of its affiliates that may only be used to fund all or a portion of certain funded acquisitions or growth capital expenditures. During the nine months ended September 30, 2018, the Company drew and repaid $86.0 million under the Sponsor Line.
(3)
Represents short-term and long-term restricted cash and includes $11.7 million of cash trapped at our project-level subsidiaries as of September 30, 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 (see Note 2. Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements for additional details).

Repricing Amendment to the Revolver

On October 5, 2018, the Company entered into a repricing amendment to the Revolver whereby the interest rate was reduced by 0.75% per annum. The Revolver would bear interest at a rate equal to, at the Company’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. In addition, the repricing amendment extended the maturity date of the Revolver to October 5, 2023. The Company did not incur additional debt or receive any proceeds in connection with the repricing amendment.

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 2022 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 September 30, 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)
 
Remainder of 2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Total
Maturities of long-term debt1
 
$
90,947

 
$
257,488

 
$
256,380

 
$
259,267

 
$
751,624

 
$
4,381,388

 
$
5,997,094



64



————
(1)
Represents the contractual principal payment due dates for our long-term debt and does not reflect the reclassification of $193.9 million of long-term debt to current as a result of debt defaults under certain of our non-recourse financing arrangements (see Note 8. Long-term Debt to our unaudited condensed 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 nine months ended September 30, 2018. TerraForm Power did not declare or pay a dividend during the nine months ended September 30, 2017.
 
Dividends per Share
 
Declaration Date
 
Record Date
 
Payment Date
First Quarter
$
0.19

 
February 6, 2018
 
February 28, 2018
 
March 30, 2018
Second Quarter
0.19

 
April 30, 2018
 
June 1, 2018
 
June 15, 2018
Third Quarter
0.19

 
August 13, 2018
 
September 1, 2018
 
September 15, 2018

On November 8, 2018, the Board of Directors of the Company declared a fourth-quarter 2018 dividend with respect to its Class A common stock of $0.19 per share. The dividend is payable on December 17, 2018 to shareholders of record as of December 3, 2018.

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 of 1934. 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 September 30, 2018, no shares were repurchased under the program.
 
Incentive Distribution Rights
    
SunEdison 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”), 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 (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:

•
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.



65



There were no IDR payments made by us during the nine months ended September 30, 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.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The following table reflects the changes in cash flows for the comparative periods:
(In thousands)
 
Nine Months Ended September 30,
 
 
 
2018
 
2017
 
Change
Net cash provided by operating activities
 
$
151,027

 
$
92,365

 
$
58,662

Net cash (used in) provided by investing activities
 
(874,876
)
 
199,384

 
(1,074,260
)
Net cash provided by (used in) financing activities
 
1,012,807

 
(417,647
)
 
1,430,454


Net Cash Provided By Operating Activities

Net cash provided by operating activities was $151.0 million for the nine months ended September 30, 2018, as compared to $92.4 million for the same period in the prior year. The increase in operating cash flow of $58.7 million was primarily driven by an $86.1 million increase in operating revenues for the period (excluding gains on commodity contracts derivatives, recognition of deferred revenue and amortization of favorable and unfavorable rate revenue contracts, net), which was partially offset by an increase of $20.8 million in the cost of operations (excluding the losses on the disposal of property, plant and equipment). The increase in cash earnings was primarily driven by the acquisition of Saeta in June of 2018.

Net Cash (Used In) Provided By Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2018, was $874.9 million, which was due to: (i) $886.1 million of payments to acquire the Tendered Shares of Saeta, net of cash and restricted cash acquired; (ii) a $4.1 million payment to acquire certain solar facilities from third parties, net of cash and restricted cash acquired; (iii) the use of $15.3 million for capital expenditures; (iv) the proceeds from the settlement of foreign currency contracts used to hedge the exposure associated with foreign subsidiaries of $22.4 million and (v) the receipt of $8.2 million of proceeds received from a government rebate for certain costs previously incurred for capital expenditures. Net cash provided by investing activities for the nine months ended September 30, 2017, was $199.4 million, which was due to: (i) $183.2 million of net proceeds received from the sale of renewable energy facilities; (ii) $23.6 million of proceeds received from a government rebate for certain costs incurred for capital expenditures; and (iii) the use of $7.5 million for capital expenditures.

Net Provided By (Used In) Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2018, was $1,012.8 million, primarily due to $650.0 million proceeds received from the private placement to affiliates of Brookfield, net draws of $418.5 million on our revolving credit facilities and net issuances of $56.3 million of non-recourse long-term debt, which were partially offset by $95.6 million of dividend payments to our Class A common stockholders.

Net cash used in financing activities for the nine months ended September 30, 2017, was $417.6 million, primarily due to $199.5 million of principal payments and prepayments on non-recourse debt and repayments of $275.0 million on revolving credit facilities, which was partially offset by $79.8 million of proceeds received from increasing our Canadian project-level financing. 

Off-Balance Sheet Arrangements

The Company enters into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. See Note 14. Commitments and Contingencies to our unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q for additional discussion.



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Critical Accounting Policies and Estimates

The accompanying unaudited condensed consolidated financial statements provided herein were prepared in accordance with U.S. GAAP. In preparing the accompanying financial statements, we have applied accounting policies and made certain estimates and assumptions that affect the reported amounts of assets, liabilities, stockholders’ equity, revenues and expenses, and the disclosures thereof. While we believe that these policies and estimates used are appropriate, actual future events can and often do result in outcomes that can differ from these estimates. The accounting policies and related risks described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, are those that depend most heavily on these judgments and estimates. As of September 30, 2018, the only notable changes to the significant accounting policies described in our Annual Report on Form 10-K are with respect to our adoption of the new accounting pronouncements described in Note 2. Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements.

Recently Issued Accounting Standards

See Note 2. Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q for disclosures concerning recently issued accounting standards. These disclosures are incorporated herein by reference.

Item 3. 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 September 30, 2018, the estimated fair value of our debt was $6,052.9 million and the carrying value of our debt was $5,954 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 $84 million and $109 million, respectively.

As of September 30, 2018, our corporate-level debt consisted of the Senior Notes due 2023 (fixed rate), the Senior Notes due 2025 (fixed rate) and the Revolver (variable rate). We have not entered into any interest rate derivatives to swap our variable rate corporate-level debt to a fixed rate, and thus we are exposed to fluctuations in interest rate risk. A hypothetical increase or decrease in interest rates by 1% would have increased or decreased interest expense related to our Revolver by $2.2 million for the nine months ended September 30, 2018.

As of September 30, 2018, our non-recourse permanent financing debt was at both fixed and variable rates. 56% of the $3,553.3 million balance had a variable interest rate and the remaining 44% of the balance had a fixed interest rate. We have entered into interest rate derivatives to swap certain 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.

Foreign Currency Risk

During the nine months ended September 30, 2018 and 2017, we generated operating revenues in the United States (including Puerto Rico), Canada, the United Kingdom, Chile, Spain, Uruguay, and Portugal with our revenues being denominated in U.S. dollars, Canadian dollars, British pounds, and Euros. The PPAs, operating and maintenance agreements, financing arrangements and other contractual arrangements relating to our current portfolio are denominated in U.S. dollars, Canadian dollars, British pounds, and Euros.



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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 and liabilities denominated in Euros. 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 $10.0 million for the nine months ended September 30, 2018.

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 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 unaudited consolidated condensed statements of cash flows.

Commodity Risk

For certain of our wind power plans, we 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 1,000 bps, or 10%, increase or decrease in electricity sales prices pertaining to commodity swaps not designated as hedges would have decreased or increased our earnings by $9.7 million for the nine months ended September 30, 2018.

Liquidity Risk

The Company's 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. The Company's ability to meet its debt service obligations and other capital requirements, including capital expenditures, as well as make acquisitions, will depend on the Company's 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.

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by offtake counterparties or SunEdison 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 offtake counterparties. 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. If any of these receivable balances in the future should be deemed uncollectible, it could have a material adverse effect on our forecasted cash flows.



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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, management identified material weaknesses in the Company’s internal control over financial reporting. We carried out an evaluation as of September 30, 2018, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were ineffective as of September 30, 2018 due to the previously identified material weaknesses, which continued to exist as of September 30, 2018.

We performed additional analysis and other procedures in order to prepare the unaudited condensed consolidated financial information in accordance with U.S. GAAP. Notwithstanding such material weaknesses in internal control over financial reporting, our management concluded that our unaudited condensed consolidated financial information presents fairly, in all material respects, the Company’s financial position, results of operations and cash flows as of the dates, and for the periods presented, in conformity with generally accepted accounting principles.

As permitted by SEC guidance, management has not evaluated the internal controls of the recently acquired Saeta business, and therefore, management’s assessment of the Company’s internal control over financial reporting does not include an assessment of the internal control over financial reporting of Saeta.

Changes in Internal Control Over Financial Reporting

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 Exchange Act) during the three months ended September 30, 2018, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting other than the remediation actions discussed below. The Company continues to implement its remediation plan as described in Item 9A. Controls and Procedures in our Annual Report on Form 10-K for the year ended December 31, 2017. We are continuing to address the material weaknesses and are committed to the remediation of such material weaknesses as timely as possible.

During the third quarter of 2018, we executed the following actions:

•
We substantially completed the hiring of key permanent accounting, finance, and IT personnel and continued refining the future state organization to ensure appropriate segregation of duties and internal control accountability;
•
We deployed a new cloud-based accounting system and began the process of implementing additional consolidation and treasury related financial systems, each of which is expected to increase the efficiency of processing transactions and to produce accurate and timely information in order to address various operational and compliance needs; and
•
We continued our efforts to implement our remediation plans, which include redesigning, enhancing and implementing new key internal controls, training of new process owners and updating certain policies and procedures.





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PART II - Other Information

Item 1. Legal Proceedings.

For a description of our legal proceedings, see Item 1. Note 14. Commitments and Contingencies to our unaudited condensed consolidated financial statements.

Item 1A. Risk Factors.

In addition to the information set forth elsewhere in this Quarterly Report on Form 10-Q, you should carefully consider the factors under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017, which was filed on March 7, 2018. These risks could materially and adversely affect our business, financial condition and results of operations. There have been no material changes in the Company’s risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2017 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

As described in Item 1. Note 12. Stockholders’ Equity to our unaudited condensed consolidated financial statements, 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. The net losses for the Chamblee Class Action include the $1.13 million contributed by the Company to the settlement but do not include the $13.63 million contributed by the Company’s insurers and certain attorneys’ fees that TerraForm Global, Inc. reimbursed to the Company pursuant to the insurance allocation arrangements entered into with the Company in 2017.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.



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Item 6. Exhibits.

Exhibit
Number
 
Description
 
 
 
 
 
 
10.1
 
31.1
 
31.2
 
32
 
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




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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

TERRAFORM POWER, INC.
 
 
 
 
 
 
 
 
By:
/s/ MATTHEW BERGER
 
By:
/s/ MICHAEL RAGUSA
 
 
Name:
Matthew Berger
 
 
Name:
Michael Ragusa
 
 
Title:
Chief Financial Officer (principal financial officer)
 
 
Title:
Chief Accounting Officer (principal accounting officer)
 
 
 
 
 
 
 
 
 
Date:
November 9, 2018
 
 
Date:
November 9, 2018

    




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