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EX-32 - EXHIBIT 32 - Pattern Energy Group Inc.pegi2017033110qexhibit32.htm
EX-31.2 - EXHIBIT 31.2 - Pattern Energy Group Inc.pegi2017033110qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Pattern Energy Group Inc.pegi2017033110qexhibit311.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
 
 
 
FORM 10-Q
 
 
 
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2017.
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36087
 
 
 
PATTERN ENERGY GROUP INC.
(Exact name of Registrant as specified in its charter)
 
 
 
Delaware
 
90-0893251
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
Pier 1, Bay 3, San Francisco, CA 94111
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (415) 283-4000
 
 
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes     No  
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes      No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
 
 
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.)    Yes      No  
As of May 4, 2017 there were 87,616,747 shares of Class A common stock outstanding with par value of $0.01 per share.
 




PATTERN ENERGY GROUP INC.
REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2017
TABLE OF CONTENTS
 
 
PART I. FINANCIAL INFORMATION
 
Item 1.
 
 
 
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
 
PART II. OTHER INFORMATION
 
 
 
 
Item 1.
Item 1A.
Item 6.
 



2


CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements and information in this Quarterly Report on Form 10-Q (Form 10-Q) may constitute “forward-looking statements.” You can identify these statements by forward-looking words such as "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "potential," "should," "will," "would," or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
our ability to complete acquisitions of power projects;
our ability to complete construction of our construction projects and transition them into financially successful operating projects;
fluctuations in supply, demand, prices and other conditions for electricity, other commodities and renewable energy credits (RECs);
our electricity generation, our projections thereof and factors affecting production, including wind and other conditions, other weather conditions, availability and curtailment;
changes in law, including applicable tax laws;
public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including the U.S. federal production tax credit (PTC), investment tax credit (ITC) and potential reductions in Renewable Portfolio Standards (RPS) requirements;
the ability of our counterparties to satisfy their financial commitments or business obligations;
the availability of financing, including tax equity financing, for our power projects;
an increase in interest rates;
our substantial short-term and long-term indebtedness, including additional debt in the future;
competition from other power project developers;
development constraints, including the availability of interconnection and transmission;
potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;
our ability to operate our business efficiently, manage capital expenditures and costs effectively and generate cash flow;
our ability to retain and attract executive officers and key employees;
our ability to keep pace with and take advantage of new technologies;
the effects of litigation, including administrative and other proceedings or investigations, relating to our wind power projects under construction and those in operation;
conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuations and general economic conditions;
the effectiveness of our currency risk management program;
the effective life and cost of maintenance of our wind turbines and other equipment;
the increased costs of, and tariffs on, spare parts;
scarcity of necessary equipment;
negative public or community response to wind power projects;
the value of collateral in the event of liquidation; and
other factors discussed under “Risk Factors.”

3


For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part II, "Item 1A. Risk Factors" in this Form 10-Q and Part I, "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2016.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.


4


PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Pattern Energy Group Inc.
Consolidated Balance Sheets
(In thousands of U.S. Dollars, except share data)
(Unaudited)
 
March 31,
 
December 31,

2017
 
2016
Assets

 

Current assets:

 

Cash and cash equivalents (Note 4)
$
244,675

 
$
83,932

Restricted cash (Note 4)
8,493

 
11,793

Funds deposited by counterparty
41,977

 
43,635

Trade receivables (Note 4)
45,998

 
37,510

Derivative assets, current
18,098

 
17,578

Prepaid expenses (Note 4)
12,857

 
13,803

Deferred financing costs, current, net of accumulated amortization of $9,964 and $9,350 as of March 31, 2017 and December 31, 2016, respectively
2,449

 
2,456

Other current assets (Note 4)
11,387

 
7,350

Total current assets
385,934

 
218,057

Restricted cash (Note 4)
17,117

 
13,646

Property, plant and equipment, net
3,095,179

 
3,135,162

Unconsolidated investments
232,735

 
233,294

Derivative assets
23,385

 
26,712

Deferred financing costs
3,370

 
4,052

Net deferred tax assets
5,903

 
5,559

Finite-lived intangible assets, net
90,202

 
91,895

Other assets (Note 4)
21,399

 
24,390

Total assets
$
3,875,224

 
$
3,752,767

Liabilities and equity

 

Current liabilities:

 

Accounts payable and other accrued liabilities (Note 4)
$
26,847

 
$
31,305

Accrued construction costs (Note 4)
848

 
1,098

Counterparty deposit liability
41,977

 
43,635

Accrued interest (Note 4)
6,802

 
9,545

Dividends payable
36,527

 
35,960

Derivative liabilities, current
11,877

 
11,918

Revolving credit facility

 
180,000

Current portion of long-term debt, net
50,715

 
48,716

Other current liabilities (Note 4)
3,723

 
4,698

Total current liabilities
179,316

 
366,875

Long-term debt, net
1,669,680

 
1,334,956

Derivative liabilities
21,553

 
24,521

Net deferred tax liabilities
37,435

 
31,759

Finite-lived intangible liability, net
53,796

 
54,663

Other long-term liabilities (Note 4)
65,212

 
61,249

Total liabilities
2,026,992

 
1,874,023

Commitments and contingencies (Note 12)


 


Equity:

 

Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 87,616,747 and 87,410,687 shares outstanding as of March 31, 2017 and December 31, 2016, respectively
877

 
875

Additional paid-in capital
1,110,412

 
1,145,760

Accumulated loss
(88,617
)
 
(94,270
)
Accumulated other comprehensive loss
(57,492
)
 
(62,367
)
Treasury stock, at cost; 110,964 and 110,964 shares of Class A common stock as of March 31, 2017 and December 31, 2016, respectively
(2,500
)
 
(2,500
)
Total equity before noncontrolling interest
962,680

 
987,498

Noncontrolling interest
885,552

 
891,246

Total equity
1,848,232

 
1,878,744

Total liabilities and equity
$
3,875,224

 
$
3,752,767

See accompanying notes to consolidated financial statements.

5


Pattern Energy Group Inc.
Consolidated Statements of Operations
(In thousands of U.S. Dollars, except share data)
(Unaudited)

 
Three months ended March 31,
 
2017
 
2016
Revenue:
 
 
 
Electricity sales
$
98,434

 
$
85,663

Other revenue
2,399

 
1,976

Total revenue
100,833

 
87,639

Cost of revenue:
 
 
 
Project expense
29,170

 
32,246

Depreciation and accretion
43,740

 
43,411

Total cost of revenue
72,910

 
75,657

Gross profit
27,923

 
11,982

Operating expenses:
 
 
 
General and administrative (Note 13)
11,124

 
8,562

Related party general and administrative
3,426

 
1,897

Total operating expenses
14,550

 
10,459

Operating income
13,373

 
1,523

Other income (expense):
 
 
 
Interest expense
(22,555
)
 
(21,061
)
Loss on undesignated derivatives, net
(648
)
 
(13,631
)
Earnings in unconsolidated investments
16,876

 
3,830

Net (loss) gain on transactions
(312
)
 
33

Other income, net
580

 
1,556

Total other expense
(6,059
)
 
(29,273
)
Net income (loss) before income tax
7,314

 
(27,750
)
Tax provision
4,775

 
1,298

Net income (loss)
2,539

 
(29,048
)
Net loss attributable to noncontrolling interest
(3,114
)
 
(5,378
)
Net income (loss) attributable to Pattern Energy
$
5,653

 
$
(23,670
)
 
 
 
 
Weighted-average number of common shares outstanding
 
 
 
Basic
87,062,612

 
74,437,998

Diluted
87,131,280

 
74,437,998

Earnings (loss) per share attributable to Pattern Energy
 
 
 
Basic and diluted
$
0.06

 
$
(0.32
)
Dividends declared per Class A common share
$
0.41

 
$
0.38


See accompanying notes to consolidated financial statements.

6


Pattern Energy Group Inc.
Consolidated Statements of Comprehensive Income (Loss)
(In thousands of U.S. Dollars)
(Unaudited)

 
 
Three months ended March 31,
 
 
2017
 
2016
Net income (loss)
 
$
2,539

 
$
(29,048
)
Other comprehensive income (loss):
 
 
 
 
Foreign currency translation, net of zero tax impact
 
2,463

 
10,862

Derivative activity:
 
 
 
 
Effective portion of change in fair market value of derivatives, net of tax benefit of $39 and $2,723, respectively
 
(541
)
 
(20,697
)
Reclassifications to net income (loss), net of tax impact of $251 and $302, respectively
 
2,319

 
2,902

Total change in effective portion of change in fair market value of derivatives
 
1,778

 
(17,795
)
Proportionate share of equity investee’s derivative activity:
 
 
 
 
Effective portion of change in fair market value of derivatives, net of tax benefit of $779 and $2,673, respectively
 
(2,160
)
 
(7,414
)
Reclassifications to net income(loss), net of tax impact of $1,032 and $452, respectively
 
2,861

 
1,253

Total change in effective portion of change in fair market value of derivatives
 
701

 
(6,161
)
Total other comprehensive income (loss), net of tax
 
4,942

 
(13,094
)
Comprehensive income (loss)
 
7,481

 
(42,142
)
Less comprehensive loss attributable to noncontrolling interest:
 
 
 
 
Net loss attributable to noncontrolling interest
 
(3,114
)
 
(5,378
)
Derivative activity:
 
 
 
 
Effective portion of change in fair market value of derivatives, net of tax benefit of $8 and $343, respectively
 
(21
)
 
(928
)
Reclassifications to net loss, net of tax impact of $33 and $47, respectively
 
88

 
128

Total change in effective portion of change in fair market value of derivatives
 
67

 
(800
)
Comprehensive loss attributable to noncontrolling interest
 
(3,047
)
 
(6,178
)
Comprehensive income (loss) attributable to Pattern Energy
 
$
10,528

 
$
(35,964
)
See accompanying notes to consolidated financial statements.

7



Pattern Energy Group Inc.
Consolidated Statements of Stockholders’ Equity
(In thousands of U.S. Dollars, except share data)
(Unaudited)
 
 
Class A Common Stock
 
Treasury Stock
 
Additional Paid-in Capital
 
Accumulated Loss
 
Accumulated Other Comprehensive Loss
 
Total
 
Noncontrolling Interest
 
Total Equity
 
Shares
 
Amount
 
Shares
 
Amount
 
Balances at December 31, 2015
74,709,442

 
$
747

 
(65,301
)
 
$
(1,577
)
 
$
982,814

 
$
(77,159
)
 
$
(73,325
)
 
$
831,500

 
$
944,262

 
$
1,775,762

Issuance of Class A common stock under equity incentive award plan
287,904

 
3

 

 

 
(3
)
 

 

 

 

 

Repurchase of shares for employee tax withholding

 

 
(1,075
)
 
(19
)
 

 

 

 
(19
)
 

 
(19
)
Stock-based compensation

 

 

 

 
1,195

 

 

 
1,195

 

 
1,195

Dividends declared

 

 

 

 
(28,567
)
 

 

 
(28,567
)
 

 
(28,567
)
Distributions to noncontrolling interests

 

 

 

 

 

 

 

 
(3,917
)
 
(3,917
)
Other

 

 

 

 
16

 

 

 
16

 
(465
)
 
(449
)
Net loss

 

 

 

 

 
(23,670
)
 

 
(23,670
)
 
(5,378
)
 
(29,048
)
Other comprehensive loss, net of tax

 

 

 

 

 

 
(12,294
)
 
(12,294
)
 
(800
)
 
(13,094
)
Balances at March 31, 2016
74,997,346

 
$
750

 
(66,376
)
 
$
(1,596
)
 
$
955,455

 
$
(100,829
)
 
$
(85,619
)
 
$
768,161

 
$
933,702

 
$
1,701,863

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2016
87,521,651

 
$
875

 
(110,964
)
 
$
(2,500
)
 
$
1,145,760

 
$
(94,270
)
 
$
(62,367
)
 
$
987,498

 
$
891,246

 
$
1,878,744

Issuance of Class A common stock under equity incentive award plan
206,060

 
2

 

 

 
(2
)
 

 

 

 

 

Stock-based compensation

 

 

 

 
985

 

 

 
985

 

 
985

Dividends declared

 

 

 

 
(36,258
)
 

 

 
(36,258
)
 

 
(36,258
)
Distributions to noncontrolling interests

 

 

 

 

 

 

 

 
(2,647
)
 
(2,647
)
Other

 

 

 

 
(73
)
 

 

 
(73
)
 

 
(73
)
Net income (loss)

 

 

 

 

 
5,653

 

 
5,653

 
(3,114
)
 
2,539

Other comprehensive income, net of tax

 

 

 

 

 

 
4,875

 
4,875

 
67

 
4,942

Balances at March 31, 2017
87,727,711

 
$
877

 
(110,964
)
 
$
(2,500
)
 
$
1,110,412

 
$
(88,617
)
 
$
(57,492
)
 
$
962,680

 
$
885,552

 
$
1,848,232


See accompanying notes to consolidated financial statements.

8


Pattern Energy Group Inc.
Consolidated Statements of Cash Flows
(In thousands of U.S. Dollars)
(Unaudited)

 
Three months ended March 31,

2017
 
2016
Operating activities

 

Net income (loss)
$
2,539

 
$
(29,048
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 


Depreciation and accretion
43,740

 
43,411

Amortization of financing costs
1,858

 
1,746

Amortization of debt discount/premium, net
1,102

 
1,032

Amortization of power purchase agreements, net
736

 
753

Loss on derivatives, net
2,350

 
17,757

Stock-based compensation
985

 
1,195

Deferred taxes
4,693

 
1,143

Earnings in unconsolidated investments, net
(16,876
)
 
(3,517
)
Distributions from unconsolidated investments
16,487

 

Other reconciling items
(439
)
 
(784
)
Changes in operating assets and liabilities:


 


Funds deposited by counterparty
1,658

 
(61,177
)
Trade receivables
(8,432
)
 
3,215

Prepaid expenses
946

 
1,360

Other current assets
(4,083
)
 
1,114

Other assets (non-current)
2,992

 
(236
)
Accounts payable and other accrued liabilities
(4,418
)
 
(18,671
)
Counterparty deposit liability
(1,658
)
 
61,177

Accrued interest
(2,725
)
 
(6,235
)
Other current liabilities
(975
)
 
(1,218
)
Long-term liabilities
3,272

 
1,704

Net cash provided by operating activities
43,752

 
14,721

Investing activities

 

Cash paid for acquisitions, net of cash acquired
(275
)
 

Capital expenditures
(1,328
)
 
(24,084
)
Distributions from unconsolidated investments
4,205

 
19,814

Other investing activities
83

 
(125
)
Net cash provided by (used in) investing activities
2,685

 
(4,395
)

9


Pattern Energy Group Inc.
Consolidated Statements of Cash Flows
(In thousands of U.S. Dollars)
(Unaudited)

 
Three months ended March 31,

2017
 
2016
Financing activities

 

Dividends paid
(35,522
)
 
(27,711
)
Capital distributions - noncontrolling interest
(2,647
)
 
(3,917
)
Payment for deferred financing costs
(5,025
)
 

Proceeds from revolving credit facility

 
20,000

Repayment of revolving credit facility
(180,000
)
 
(20,000
)
Proceeds from long-term debt
350,000

 

Repayment of long-term debt
(10,326
)
 
(8,943
)
Other financing activities
(2,003
)
 
(143
)
Net cash provided by (used in) financing activities
114,477

 
(40,714
)
Effect of exchange rate changes on cash, cash equivalents and restricted cash

 
1,837

Net change in cash, cash equivalents and restricted cash
160,914

 
(28,551
)
Cash, cash equivalents and restricted cash at beginning of period
109,371

 
146,292

Cash, cash equivalents and restricted cash at end of period
$
270,285

 
$
117,741

Supplemental disclosures

 

Cash payments for income taxes
$
247

 
$
97

Cash payments for interest expense, net of capitalized interest
$
22,607

 
$
24,204

Schedule of non-cash activities


 


Change in property, plant and equipment
$
956

 
$
11,599

Accrual of deferred financing costs
$
1,640

 
$


See accompanying notes to consolidated financial statements.

10


Pattern Energy Group Inc.
Notes to Consolidated Financial Statements
(Unaudited)
1.    Organization
Pattern Energy Group Inc. (Pattern Energy or the Company) was organized in the state of Delaware on October 2, 2012. Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. Pattern Energy Group LP (Pattern Development 1.0) owns a 19% interest in the Company. The Pattern Development Companies (Pattern Development 1.0, Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries (other than the Company and the Company's subsidiaries)) are leading developers of renewable energy and transmission projects.
The Company consists of the consolidated operations of certain entities and assets contributed by, or purchased principally from, Pattern Development 1.0, except for purchases of Lost Creek, Post Rock and certain additional interests in El Arrayán, each as defined below, which were purchased from third-parties. Each of the Company's wind projects and certain assets are consolidated into the Company's subsidiaries which are organized by geographic location as follows:
Pattern US Operations Holdings LLC (which consists primarily of 100% ownership of Hatchet Ridge Wind, LLC (Hatchet Ridge), Spring Valley Wind LLC (Spring Valley), Pattern Santa Isabel LLC (Santa Isabel), Ocotillo Express LLC (Ocotillo), Pattern Gulf Wind LLC (Gulf Wind) and Lost Creek Wind, LLC (Lost Creek), as well as the following consolidated controlling interest in Pattern Panhandle Wind LLC (Panhandle 1), Pattern Panhandle Wind 2 LLC (Panhandle 2), Post Rock Wind Power Project, LLC (Post Rock), Logan's Gap Wind LLC (Logan's Gap) and Fowler Ridge IV Wind Farm LLC (Amazon Wind Farm Fowler Ridge));
Pattern Canada Operations Holdings ULC (which consists primarily of 100% ownership of St. Joseph Windfarm Inc. (St. Joseph) and noncontrolling interests in South Kent Wind LP (South Kent), Grand Renewable Wind LP (Grand), K2 Wind Ontario Limited Partnership (K2), and SP Armow Wind Ontario LP (Armow) which are accounted for as unconsolidated investments); and
Pattern Chile Holdings LLC (which includes a controlling interest in Parque Eólico El Arrayán SpA (El Arrayán) and controlling interest in Don Goyo Transmisión S.A. (Don Goyo), a transmission asset of El Arrayán).
On April 21, 2017, the Company acquired controlling interests in the two wind projects that comprise the 324 megawatt (MW) Broadview Wind power facilities (Broadview) and associated independent 35-mile 345 kV Western Interconnect transmission line (Western Interconnect) from Pattern Development 1.0 (Broadview Transaction). See Note 14, Subsequent Events in the Notes to Consolidated Financial Statements in this Form 10-Q, for further discussion.
2.    Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The 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 in consolidation.
Unaudited Interim Financial Information
The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (U.S. GAAP) for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (SEC). Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, the interim financial information reflects all adjustments of a normal recurring nature, necessary for a fair presentation of the Company’s financial position at March 31, 2017, the results of operations and comprehensive income (loss) for the three months ended March 31, 2017 and 2016, respectively, and the cash flows for the three months ended March 31, 2017 and 2016, respectively. The consolidated balance sheet at December 31, 2016 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. This Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

11


Use of Estimates
The preparation of the financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates, and such differences may be material to the financial statements.
Reclassification
Certain prior period balances have been reclassified to conform to the current period presentation in the Company’s consolidated financial statements and the accompanying notes.
The Company adopted the provisions of Accounting Standards Update (ASU) 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash as of December 31, 2016 and has revised its consolidated statements of cash flows for the three months ended March 31, 2016 to reflect amounts described as restricted cash and restricted cash equivalents included with cash and cash equivalents in the reconciliation of beginning of period and end of period total amounts shown on the consolidated statements of cash flows.
Reconciliation of Cash and Cash Equivalents and Restricted Cash as Presented on the Statements of Cash Flows
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the consolidated statements of cash flows.
 
 
March 31,
2017
 
December 31,
2016
 
March 31,
2016
December 31,
2015
Cash and cash equivalents
 
$
244,675

 
$
83,932

 
$
90,624

$
94,808

Restricted cash - current
 
8,493

 
11,793

 
10,282

14,609

Restricted cash
 
17,117

 
13,646

 
16,835

36,875

Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows
 
$
270,285

 
$
109,371

 
$
117,741

$
146,292

Recently Issued Accounting Standards
Except for the evaluation of recently issued accounting standards set forth below, there have been no changes to the Company's evaluation of other recently issued accounting standards disclosed in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.
In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, Leases, (ASU 2016-02) which requires lessees to recognize right-of-use assets and lease liabilities, for all leases, with the exception of short-term leases, at the commencement date of each lease. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 simplifies the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and liabilities. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption is permitted. The Company does not plan to early adopt, and accordingly, will adopt the new standard effective January 1, 2019. The amendments of this update should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The Company is in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and system requirements. The Company has assigned internal resources in addition to the engagement of a third party service provider to assist in evaluation. The Company is also assessing the accounting impact of the ASU 2016-02 as it applies to its PPAs, land leases, office leases and equipment leases. As the Company progresses further in its analysis, the scope of this assessment could be expanded to review other types of contracts.

In May 2014, the FASB issued a new standard, ASU 2014-09, which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes ASC Topic 605, Revenue Recognition (ASU 2014-09). The new standard replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the new standard is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the new standard requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising

12


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 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 2014-09. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606Identifying Performance Obligations and Licensing, which clarifies two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas, as updated by ASU 2014-09. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, which makes narrow scope amendments to Topic 606 including implementation issues on collectability, non-cash consideration and completed contracts at transition. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which make additional narrow scope amendments to Topic 606 including loan guarantee fees, impairment testing of contract costs, provisions for losses on construction-type and production-type contracts.

The new standard permits adoption by either using (i) the full retrospective approach for all periods presented in the period of adoption or (ii) a modified retrospective approach with the cumulative effect of initially applying the new standard recognized at the date of initial application and providing certain additional disclosures. The Company plans to adopt using the modified retrospective approach. The new standard is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted for annual reporting periods beginning after December 15, 2016. The Company does not plan to early adopt, and accordingly, will adopt the new standard effective January 1, 2018.

The Company is in the initial stages of evaluating the impact of the new standard on its accounting policies, processes and system requirements. The Company has assigned internal resources in addition to the engagement of a third party service provider to assist in evaluation. The Company is also assessing the accounting impact of the new standard as it applies certain elements of its revenue arrangements such as contracts that contain the sale of electricity and related renewable energy credits, contracts that contain volume variability, and contracts that contain modification clauses. The Company is assessing whether revenue agreements that contain the sale of both electricity and renewable energy credits, represent separate performance obligations pursuant to the new standard, which would require the transaction price to be allocated to each of the electricity and the renewable energy credit components based on their relative standalone selling prices. In addition, the Company is assessing if the use of the residual approach is appropriate in determining the standalone selling price for renewable energy credits in situations where the standalone selling price of renewable credits is highly variable or uncertain. Under the residual value approach, the standalone selling price of renewable energy credits would be determined by reference to the total transaction price of the revenue agreement less the sum of the observable standalone selling price of the electricity. Further, the Company is in the process of assessing the disclosure impacts of the new standard to the Company’s systems and processes over revenue recognition. As the Company progresses further in its analysis, the scope of this assessment could be expanded to include other contract elements that could have an accounting impact under the new standard.

The Company continues to assess the potential impacts of the new standard and cannot reasonably estimate quantitative information related to the impact of the new standard on its consolidated financial statements at this time.

3.    Property, Plant and Equipment
The following presents the categories within property, plant and equipment (in thousands):
 
March 31,
 
December 31,
 
2017
 
2016
Operating wind farms
$
3,711,183

 
$
3,707,823

Furniture, fixtures and equipment
9,608

 
9,307

Land
141

 
141

Subtotal
3,720,932

 
3,717,271

Less: accumulated depreciation
(625,753
)
 
(582,109
)
Property, plant and equipment, net
$
3,095,179

 
$
3,135,162

The Company recorded depreciation expense related to property, plant and equipment of $43.0 million and $42.7 million for the three months ended March 31, 2017 and 2016, respectively.

13


4.     Variable Interest Entities
The Company has determined that Logan's Gap, Panhandle 1, Panhandle 2, Post Rock and Amazon Wind Farm Fowler Ridge are variable interest entities (VIEs) in accordance with ASU 2015-02 primarily because the tax equity interests in these operating entities lack substantive kick-out and participating rights. The Company determined that as the managing member it is the primary beneficiary of each VIE by reference to the power and benefits criterion under Accounting Standards Codification (ASC) 810, Consolidation. The Company considered responsibilities within the contractual agreements, which grant it the power to direct the activities of the VIE that most significantly impact the VIE's economic performance. Such activities include management of the wind farms' operations and maintenance, budgeting, policies and procedures. In addition, the Company has the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIEs on the basis of the income allocations and cash distributions.
The following presents the carrying amounts of the consolidated VIEs' assets and liabilities included in the consolidated balance sheet (in thousands). Assets presented below are restricted for settlement of the consolidated VIEs' obligations and all liabilities presented below can only be settled using the VIE resources.
 
March 31,
2017
 
December 31,
2016
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
13,109

 
$
12,745

Restricted cash
4,295

 
4,291

Trade receivables
7,876

 
6,290

Prepaid expenses
3,914

 
4,468

Other current assets
1,194

 
1,456

Total current assets
30,388

 
29,250

 
 
 
 
Restricted cash
2,354

 
3,203

Property, plant and equipment, net
1,520,762

 
1,538,793

Finite-lived intangible assets, net
2,027

 
2,070

Other assets
13,582

 
13,622

Total assets
$
1,569,113

 
$
1,586,938

 
 
 
 
Liabilities
 
 
 
Current liabilities:
 
 
 
Accounts payable and other accrued liabilities
$
5,193

 
12,635

Accrued construction costs
473

 
709

Accrued interest
75

 
77

Other current liabilities
1,551

 
2,090

Total current liabilities
7,292

 
15,511

 
 
 
 
Finite-lived intangible liability, net
53,796

 
54,663

Other long-term liabilities
23,420

 
20,081

Total liabilities
$
84,508

 
$
90,255


14


5.    Unconsolidated Investments
The Company's unconsolidated investments consist of the following for the periods presented below (in thousands):
 
 
 
 
 
Percentage of Ownership
 
March 31,
 
December 31,
 
March 31,
 
December 31,
 
2017
 
2016
 
2017
 
2016
South Kent
$
4,277

 
$
1,537

 
50.0
%
 
50.0
%
Grand
4,695

 
3,459

 
45.0
%
 
45.0
%
K2
95,899

 
97,051

 
33.3
%
 
33.3
%
Armow
127,864

 
131,247

 
50.0
%
 
50.0
%
Unconsolidated investments
$
232,735

 
$
233,294

 
 
 
 
Basis Amortization of Unconsolidated Investments
The cost of the Company’s investment in the net assets of unconsolidated investments was higher than the fair value of the Company’s equity interest in the underlying net assets of its unconsolidated investments. The basis differences were attributable to property, plant and equipment and PPAs and are being amortized over the particular assets useful life. For the three months ended March 31, 2017 and 2016, the Company recorded basis difference amortization for its unconsolidated investments of $2.8 million and $1.2 million, respectively, in earnings in unconsolidated investments, net on the consolidated statements of operations.
Suspension of Equity Method Accounting
As discussed in Note 2, Summary of Significant Accounting Policies in the Company's 2016 Form-10K, the Company may suspend recognition of equity method earnings when the Company receives distributions in excess of the carrying value of its investment, and the Company is not liable for the obligations of the investee nor otherwise committed to provide financial support, the Company recognizes such excess distributions as equity method earnings in the period the distributions occur. Additionally, when the Company's carrying value in an unconsolidated investment is zero and the Company is not liable for the obligations of the investee nor otherwise committed to provide financial support, the Company will not recognize equity in earnings (losses) or equity in other comprehensive income of unconsolidated investments.
During the three months ended March 31, 2017, none of the Company's unconsolidated investments were in suspension. During the three months ended March 31, 2016, the Company's equity method balance for South Kent was zero. In accordance with ASC 323, Investments - Equity Method and Joint Ventures, the Company suspended recognition of South Kent's equity method earnings or losses until the fourth quarter of 2016 when South Kent's cumulative equity method earnings exceeded cumulative distributions received and cumulative equity method losses. As the Company has no explicit or implicit commitment to fund losses at the unconsolidated investments, the Company recorded distributions received in excess of the carrying amount of its unconsolidated investments as gains. For the three months ended March 31, 2016, earnings in unconsolidated investments, net as reported on the consolidated statements of operations attributable to South Kent included $1.7 million in distributions received in excess of the carrying amount of the Company's investment.
During the suspension period, the Company maintains a memo ledger that records the components of the suspended activity. As of March 31, 2016, the memo ledger balance was made up of distributions received in excess of the carrying amount of the Company's investment of $1.7 million.

15


Aggregate Financial Data for Unconsolidated Investees
The following summarizes the statements of operations, in aggregate, for the unconsolidated investees (in thousands):
 
 
Three months ended March 31,
 
 
2017
 
2016(1)
Revenue
 
$
100,359

 
$
72,416

Cost of revenue
 
29,589

 
22,427

Operating expenses
 
714

 
446

Other expense
 
22,841

 
38,090

Net income
 
$
47,215

 
$
11,453

(1) 
Results for the three months ended March 31, 2016 does not include Armow, which was acquired in October 2016.
Significant Equity Method Investees
The following table presents summarized statements of operations information for the three months ended March 31, 2017 and 2016, in thousands, as required for the Company's significant equity method investees, South Kent, K2 and Armow pursuant to Regulation S-X Rule 10-01(b)(1):
South Kent
 
 
Three months ended March 31,
 
 
2017
 
2016
Revenue
 
$
32,154

 
$
28,529

Cost of revenue
 
8,452

 
7,996

Operating expenses
 
189

 
189

Other expense
 
6,143

 
19,689

Net income
 
$
17,370

 
$
655

K2
 
 
Three months ended March 31,
 
 
2017
 
2016
Revenue
 
$
32,540

 
$
29,850

Cost of revenue
 
9,765

 
9,576

Operating expenses
 

 

Other expenses
 
7,180

 
7,177

Net income
 
$
15,595

 
$
13,097

Armow
 
Three months ended March 31,
 
2017
 
2016
Revenue(1)
$
21,208

 
N/A
Cost of revenue(1)
6,113

 
N/A
Operating expenses(1)
271

 
N/A
Other expenses(1)
4,383

 
N/A
Net income(1)
$
10,441

 
N/A
(1)    Results for the three months ended March 31, 2016 does not include Armow, which was acquired in October 2016.

16



6.    Debt
The Company’s debt consists of the following for periods presented below (in thousands):
 
 
 
 
 
As of March 31, 2017
 
March 31, 2017
 
December 31, 2016
 
Contractual Interest Rate
 
Effective Interest Rate
 
 
 
 
 
 
 
Maturity
Corporate-level
 
 
 
 
 
 
 
 
 
Revolving Credit Facility
$

 
$
180,000

 
varies

(1) 
varies

(1) 
December 2018
2020 Notes
225,000

 
225,000

 
4.00
%
 
6.60
%
 
July 2020
2024 Notes
350,000

 

 
5.88
%
 
5.88
%
 
February 2024
Project-level
 
 
 
 
 
 
 
 
 
Fixed interest rate
 
 
 
 
 
 
 
 
 
El Arrayán EKF term loan
101,984

 
103,904

 
5.56
%
 
5.56
%
 
March 2029
Santa Isabel term loan
106,165

 
107,090

 
4.57
%
 
4.57
%
 
September 2033
Variable interest rate
 
 
 
 
 
 
 
 
 
Ocotillo commercial term loan (2)
193,257

 
193,257

 
2.90
%
 
3.82
%
(3) 
August 2020
Lost Creek term loan
100,145

 
103,846

 
3.07
%
 
6.51
%
(3) 
September 2027
El Arrayán commercial term loan
92,713

 
94,458

 
4.17
%
 
5.70
%
(3) 
March 2029
Spring Valley term loan
128,810

 
130,658

 
2.90
%
 
5.24
%
(3) 
June 2030
Ocotillo development term loan
102,300

 
102,300

 
3.25
%
 
4.42
%
(3) 
August 2033
St. Joseph term loan (2)
163,674

 
162,356

 
2.57
%
 
3.85
%
(3) 
November 2033
Imputed interest rate
 
 
 
 
 
 
 
 
 
Hatchet Ridge financing lease obligation
202,593

 
202,593

 
1.43
%
 
1.43
%
 
December 2032
 
1,766,641

 
1,605,462

 
 
 
 
 
 
Unamortized premium/discount, net (4)
(15,917
)
 
(17,019
)
 
 
 
 
 
 
Unamortized financing costs
(30,329
)
 
(24,771
)
 
 
 
 
 
 
Total debt, net
$
1,720,395

 
1,563,672

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As reflected on the consolidated balance sheets
 
 
 
 
 
 
 
 
 
Revolving credit facility
$

 
$
180,000

 
 
 
 
 
 
Current portion of long-term debt, net of financing costs
50,715

 
48,716

 
 
 
 
 
 
Long term debt, net of financing costs
1,669,680

 
1,334,956

 
 
 
 
 
 
Total debt, net
$
1,720,395

 
$
1,563,672

 
 
 
 
 
 
(1) 
Refer to Revolving Credit Facility for interest rate details.
(2) 
The amortization for the Ocotillo commercial term loan and the St. Joseph term loan are through June 2030 and September 2036, respectively, which differs from the stated maturity date of such loans due to prepayment requirements.
(3) 
Includes impact of interest rate derivatives. See Note 7, Derivative Instruments, for discussion of interest rate derivatives.
(4) 
Premium amount is related to the Lost Creek term loan and discount amount is related to the 2020 Notes.

17


Interest and commitment fees incurred and interest expense for debt consisted of the following (in thousands):
 
Three months ended March 31,
 
2017
 
2016
Corporate-level interest, letter of credit and commitment fees incurred
$
7,115

 
$
5,053

Project-level interest, letter of credit and commitment fees incurred(1)
12,361

 
13,088

Amortization of debt discount/premium, net
1,102

 
1,032

Amortization of financing costs
1,858

 
1,746

Other interest
119

 
142

Interest expense
$
22,555

 
$
21,061

(1) 
Includes reclassification of realized gains (losses) on derivative instruments that qualifies as cash flow hedges from accumulated OCI into interest expense and the ineffective portion of the instruments.
Corporate Level Debt
Revolving Credit Facility
As of March 31, 2017, $471.8 million was available for borrowing under the $500.0 million Revolving Credit Facility. The Revolving Credit Facility is secured by pledges of the capital stock and ownership interests in certain of the Company’s holding company subsidiaries. The Revolving Credit Facility contains a broad range of covenants that, subject to certain exceptions, restrict the Company’s holding company subsidiaries' ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business. As of March 31, 2017, the Company's holding company subsidiaries were in compliance with covenants contained in the Revolving Credit Facility.
The loans under the Company's Revolving Credit Facility are either base rate loans or Eurodollar rate loans. The base rate loans accrue interest at the fluctuating rate per annum equal to the greatest of the (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the Eurodollar rate that would be in effect for a Eurodollar rate loan with an interest period of one month plus 1.0%, plus an applicable margin ranging from 1.25% to 1.75% (corresponding to applicable leverage ratios of the borrower). The Eurodollar rate loans accrue interest at a rate per annum equal to International Continental Exchange London Interbank Offered Rate (LIBOR), as published by Reuters plus an applicable margin ranging from 2.25% to 2.75% (corresponding to applicable leverage ratios of the borrower). Under the Revolving Credit Facility, the Company pays a revolving commitment fee equal to the average of the daily difference between revolving commitments and the total utilization of revolving commitments times 0.50%. The Company also pays letter of credit fees.
As of March 31, 2017 and December 31, 2016, letters of credit of $28.2 million and $31.7 million were issued under the Revolving Credit Facility.
Unsecured Senior Notes due 2024
In January 2017, the Company issued unsecured senior notes with an aggregate principal amount of $350.0 million (Unsecured Senior Notes or 2024 Notes). Net proceeds to the Company were approximately $345.0 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2024 Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The 2024 Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of the Company's subsidiaries.
Convertible Senior Notes due 2020
In July 2015, the Company issued $225.0 million aggregate principal amount of 4.00% convertible senior notes due 2020 (Convertible Senior Notes or 2020 Notes). The 2020 Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2016. The 2020 Notes will mature on July 15, 2020. The 2020 Notes were sold in a private placement.
The 2020 Notes are guaranteed on a senior unsecured basis by a subsidiary of the Company and are general unsecured obligations of the Company. The obligations rank senior in rights of payment to the Company’s subordinated debt, equal in right of payment

18


to the Company’s unsubordinated debt and effectively junior in right of payment to any of the Company’s secured indebtedness to the extent of the value of the assets securing such indebtedness.
The following table presents a summary of the equity and liability components of the 2020 Notes (in thousands):
 
March 31,
2017
 
December 31,
2016
Principal
$
225,000

 
$
225,000

Less:

 

Unamortized debt discount
(17,046
)
 
(18,196
)
Unamortized financing costs
(3,622
)
 
(3,894
)
Carrying value of convertible senior notes
$
204,332

 
$
202,910

Carrying value of the equity component (1)
$
23,743

 
$
23,743

(1) 
Included in the consolidated balance sheets as additional paid-in capital, net of $0.7 million in equity issuance costs.
7.    Derivative Instruments
The Company employs a variety of derivative instruments to manage its exposure to fluctuations in electricity prices, interest rates and foreign currency exchange rates. Energy prices are subject to wide swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists primarily on variable-rate debt for which the cash flows vary based upon movement in interest rates. Additionally, the Company is exposed to foreign currency exchange rate risk primarily from its business operations in Canada and Chile. The Company’s objectives for holding these derivative instruments include reducing, eliminating and efficiently managing the economic impact of these exposures as effectively as possible. The Company does not hedge all of its electricity price risk, interest rate risks, and foreign currency exchange rate risks, thereby exposing the unhedged portions to changes in market prices.
As of March 31, 2017, the Company had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the normal purchase normal sale scope exception and were therefore exempt from fair value accounting treatment.

19


The following tables present the fair values of the Company's derivative instruments on a gross basis as reflected on the Company’s consolidated balance sheets (in thousands):
 
 
March 31, 2017
 
 
Derivative Assets
 
Derivative Liabilities
 
 
Current
 
Long-Term
 
Current
 
Long-Term
Fair Value of Designated Derivatives
 
 
 
 
 
 
 
 
Interest rate swaps
 
$

 
$
282

 
$
8,634

 
$
18,393

 
 
 
 
 
 
 
 
 
Fair Value of Undesignated Derivatives
 
 
 
 
 
 
 
 
Interest rate swaps
 
$

 
$
2,077

 
$
2,783

 
$
3,117

Energy derivative
 
17,563

 
20,996

 

 

Foreign currency forward contracts
 
535

 
30

 
460

 
43

 
 
 
 
 
 
 
 
 
Total Fair Value
 
$
18,098

 
$
23,385

 
$
11,877

 
$
21,553

 
 
 
 
 
 
 
 
 
 
 
December 31, 2016
 
 
Derivative Assets
 
Derivative Liabilities
 
 
Current
 
Long-Term
 
Current
 
Long-Term
Fair Value of Designated Derivatives
 
 
 
 
 
 
 
 
Interest rate swaps
 
$

 
$
40

 
$
8,289

 
$
21,058

 
 
 
 
 
 
 
 
 
Fair Value of Undesignated Derivatives
 
 
 
 
 
 
 
 
Interest rate swaps
 
$

 
$
1,788

 
$
3,238

 
$
3,463

Energy derivative
 
16,209

 
24,707

 

 

Foreign currency forward contracts
 
1,369

 
177

 
391

 

 
 
 
 
 
 
 
 
 
Total Fair Value
 
$
17,578

 
$
26,712

 
$
11,918

 
$
24,521

The following table summarizes the notional amounts of the Company's outstanding derivative instruments (in thousands except for MWh):
 
 
Unit of Measure
 
March 31,
 
December 31,
 
 
 
2017
 
2016
Designated Derivative Instruments
 
 
 
 
 
 
Interest rate swaps
 
USD
 
$
360,849

 
$
365,443

Interest rate swaps
 
CAD
 
$
196,200

 
$
196,425

 
 
 
 
 
 
 
Undesignated Derivative Instruments
 
 
 
 
 
 
Interest rate swaps
 
USD
 
$
255,292

 
$
257,389

Energy derivative
 
MWh
 
1,061,077

 
1,201,691

Foreign currency forward contracts
 
CAD
 
$
136,500

 
$
95,800



20


Derivatives Designated as Hedging Instruments
Cash Flow Hedges
The Company has interest rate swap agreements to hedge variable rate project-level debt. Under these interest rate swaps, the projects make fixed-rate interest payments and the counterparties to the agreements make variable-rate interest payments. For interest swaps that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (loss) and reclassified into earnings in the period or periods during which a cash settlement occurs. The designated interest rate swaps have remaining maturities ranging from approximately 10.5 years to 19.5 years.
The following table presents the pre-tax effect of the derivative instruments designated as cash flow recognized in accumulated other comprehensive loss, as well as amounts reclassified to earnings for the following periods (in thousands):
 
 
 
 
Three months ended March 31,
 
 
Description
 
2017
 
2016
Losses recognized in accumulated OCI
 
Effective portion of change in fair value
 
$
(580
)
 
$
(23,420
)
Losses reclassified from accumulated OCI into:
 
 
 
 
 
 
Interest expense
 
Derivative settlements
 
$
(2,570
)
 
$
(3,204
)
Interest expense
 
Ineffective portion
 
$
(11
)
 
$
(89
)
The Company estimates that $6.4 million in accumulated other comprehensive income (loss) will be reclassified into earnings over the next twelve months.
Derivatives Not Designated as Hedging Instruments
The following table presents gains and losses on derivatives not designated as hedges (in thousands):
 
 
Financial Statement Line Item
 
 
 
Three months ended March 31,
Derivative Type
 
 
Description
 
2017
 
2016
Interest rate derivatives
 
Loss on undesignated derivatives, net
 
Change in fair value, net of settlements
 
$
1,090

 
$
(8,881
)
Interest rate derivatives
 
Loss on undesignated derivatives, net
 
Derivative settlements
 
$
(968
)
 
$
(1,326
)
Energy derivative
 
Electricity sales
 
Change in fair value, net of settlements
 
$
(2,358
)
 
$
(4,825
)
Energy derivative
 
Electricity sales
 
Derivative settlements
 
$
6,015

 
$
6,733

Foreign currency forward contracts
 
Loss on undesignated derivatives, net
 
Change in fair value, net of settlements
 
$
(1,094
)
 
$
(3,961
)
Foreign currency forward contracts
 
Loss on undesignated derivatives, net
 
Derivative settlements
 
$
324

 
$
537

Interest Rate Swaps
The Company has interest rate swap agreements to hedge variable rate project-level debt. Under these interest rate swaps, the projects make fixed-rate interest payments and the counterparties to the agreements make variable-rate interest payments. For interest rate swaps that are not designated and do not qualify as cash flow hedges, the changes in fair value are recorded in loss on undesignated derivatives, net in the consolidated statements of operations as these hedges are not accounted for under hedge accounting. The undesignated interest rate swaps have remaining maturities ranging from approximately 4.0 years to 13.3 years.
Energy Derivative
In 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices over the life of the arrangement. The energy price swap fixes the price for a predetermined volume of production (the notional volume) over the life of the swap contract, through April 2019, by locking in a fixed price per MWh. The notional volume agreed to by the parties is approximately 504,220 MWh per year. The energy derivative instrument does not meet the criteria required to adopt hedge accounting. As a result, changes in fair value are recorded in electricity sales in the consolidated statements of operations.

21


As a result of the counterparty's credit rating downgrade, the Company received cash collateral related to the energy derivative agreement. The Company does not have the right to pledge, invest, or use the cash collateral for general corporate purposes. As of March 31, 2017, the Company has recorded a current asset of $42.0 million to funds deposited by counterparty and a current liability of $42.0 million to counterparty deposit liability representing the cash collateral received and corresponding obligation to return the cash collateral, respectively. The cash was deposited into a separate custodial account for which the Company is not entitled to the interest earned on the cash collateral.
Foreign Currency Forward Contracts
The Company has established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in the Company’s cash flow, which may have an adverse impact to the Company's short-term liquidity or financial condition. A majority of the Company’s power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. The Company enters into foreign currency forward contracts at various times to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows. These instruments have remaining maturities ranging from two to twenty-four months. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes. As a result, changes in fair value and settlements are recorded in loss on undesignated derivatives, net in the consolidated statements of operations.
8.    Accumulated Other Comprehensive Loss
The following tables summarize the changes in the accumulated other comprehensive loss balance, net of tax, by component (in thousands):
 
Foreign Currency
 
Effective Portion of Change in Fair Value of Derivatives
 
Proportionate Share of Equity Investee’s OCI
 
Total
Balances at December 31, 2015
$
(48,285
)
 
$
(13,462
)
 
$
(12,131
)
 
$
(73,878
)
Other comprehensive income (loss) before reclassifications
10,862

 
(20,697
)
 
(7,414
)
 
(17,249
)
Amounts reclassified from accumulated other comprehensive loss

 
2,902

 
1,253

 
4,155

Net current period other comprehensive income (loss)
10,862

 
(17,795
)
 
(6,161
)
 
(13,094
)
Balances at March 31, 2016
$
(37,423
)
 
$
(31,257
)
 
$
(18,292
)
 
$
(86,972
)
Less: accumulated other comprehensive loss attributable to noncontrolling interest, March 31, 2016

 
(1,353
)
 

 
(1,353
)
Accumulated other comprehensive loss attributable to Pattern Energy, March 31, 2016
$
(37,423
)
 
$
(29,904
)
 
$
(18,292
)
 
$
(85,619
)
 
Foreign Currency
 
Effective Portion of Change in Fair Value of Derivatives
 
Proportionate Share of Equity Investee’s OCI
 
Total
Balances at December 31, 2016
$
(43,500
)
 
$
(12,751
)
 
$
(6,498
)
 
$
(62,749
)
Other comprehensive income (loss) before reclassifications
2,463

 
(541
)
 
(2,160
)
 
(238
)
Amounts reclassified from accumulated other comprehensive loss

 
2,319

 
2,861

 
5,180

Net current period other comprehensive income
2,463

 
1,778

 
701

 
4,942

Balances at March 31, 2017
$
(41,037
)
 
$
(10,973
)
 
$
(5,797
)
 
$
(57,807
)
Less: accumulated other comprehensive loss attributable to noncontrolling interest, March 31, 2017

 
(315
)
 

 
(315
)
Accumulated other comprehensive loss attributable to Pattern Energy, March 31, 2017
$
(41,037
)
 
$
(10,658
)
 
$
(5,797
)
 
$
(57,492
)
Amounts reclassified from accumulated other comprehensive loss into net income (loss) for the effective portion of change in fair value of derivatives is recorded to interest expense in the consolidated statements of operations. Amounts reclassified from accumulated other comprehensive loss into net income (loss) for the Company’s proportionate share of equity investee’s other comprehensive loss is recorded to earnings in unconsolidated investments, net in the consolidated statements of operations.

22


9.    Fair Value Measurements
The Company’s fair value measurements incorporate various factors, including the credit standing and performance risk of the counterparties, the applicable exit market, and specific risks inherent in the instrument. Nonperformance and credit risk adjustments on risk management instruments are based on current market inputs when available, such as credit default hedge spreads. When such information is not available, internal models may be used.
Assets and liabilities recorded at fair value in the consolidated financial statements are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to valuation of these assets or liabilities are set forth below. Transfers between levels are recognized at the end of each quarter. The Company did not recognize any transfers between levels during the periods presented.
Level 1—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2—Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and which reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuations technique and the risk inherent in the inputs to the model.
Financial Instruments
The carrying value of financial instruments classified as current assets and current liabilities approximates their fair value, based on the nature and short maturity of these instruments, and they are presented in the Company’s financial statements at carrying cost. The fair values of cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy. Certain other assets and liabilities were measured at fair value upon initial recognition and unless conditions give rise to an impairment, are not remeasured.
Financial Instruments Measured at Fair Value on a Recurring Basis
The Company’s financial assets and liabilities which require fair value measurement on a recurring basis are classified within the fair value hierarchy as follows (in thousands):
 
March 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
2,359

 
$

 
$
2,359

Energy derivative

 


 
38,559

 
38,559

Foreign currency forward contracts

 
565

 

 
565

 
$

 
$
2,924

 
$
38,559

 
$
41,483

Liabilities
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
32,927

 
$

 
$
32,927

Foreign currency forward contracts

 
503

 

 
503

 
$

 
$
33,430

 
$

 
$
33,430


23


 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
1,828

 
$

 
$
1,828

Energy derivative

 

 
40,916

 
40,916

Foreign currency forward contracts

 
1,546

 

 
1,546

 
$

 
$
3,374

 
$
40,916

 
$
44,290

Liabilities
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
36,048

 
$

 
$
36,048

Foreign currency forward contracts

 
391

 

 
391

 
$

 
$
36,439

 
$

 
$
36,439

Level 2 Inputs
Derivative instruments subject to re-measurement are presented in the financial statements at fair value. The Company's interest rate swaps were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the Company’s credit default hedge rate. The Company’s foreign currency forward contracts were valued using the income approach based on the present value of the forward rates less the contract rates, multiplied by the notional amounts.
Level 3 Inputs
The fair value of the energy derivative instrument is determined based on a third-party valuation model. The methodology and inputs are evaluated by management for consistency and reasonableness by comparing inputs used by the third-party valuation provider to another third-party pricing service for identical or similar instruments and also agreeing inputs used in the third-party valuation model to the derivative contract for accuracy. Any significant changes are further evaluated for reasonableness by obtaining additional documentation from the third-party valuation provider.
The energy derivative instrument is valued by discounting the projected net cash flows over the remaining life of the derivative instrument using forward electricity prices which are derived from observable prices, such as forward gas curves, adjusted by a non-observable heat rate for when the contract term extends beyond a period for which market data is available. The significant unobservable input in calculating the fair value of the energy derivative instrument is forward electricity prices. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.
The valuation techniques and significant unobservable inputs used in recurring Level 3 fair value measurements were as follows (in thousands, for fair value):
March 31, 2017
 
Fair Value
 
Valuation Technique
 
Significant Unobservable Inputs
 
Range
Energy derivative
 
$38,559
 
Discounted cash flow
 
Forward electricity prices
 
$14.75 - $82.09(1)
 
 
 
 
 
 
Discount rate
 
1.15% - 1.62%
 
 
 
 
 
 
 
December 31, 2016
 
Fair Value
 
Valuation Technique
 
Significant Unobservable Inputs
 
Range
Energy derivative
 
$40,916
 
Discounted cash flow
 
Forward electricity prices
 
$15.83 - $81.76(1)
 
 
 
 
 
 
Discount rate
 
1.00% - 1.52%
(1) 
Represents price per MWh

24


The following table presents a reconciliation of the energy derivative contract measured at fair value on a recurring basis using significant unobservable inputs (in thousands):
 
 
Three months ended March 31,
 
 
2017
 
2016
Balances, beginning of period
 
$
40,916

 
$
63,683

Total gains included in electricity sales
 
3,658

 
1,908

Settlements
 
(6,015
)
 
(6,733
)
Balances, end of period
 
$
38,559

 
$
58,858

During the three months ended March 31, 2017 and 2016, the Company recognized an unrealized loss on the energy derivative of $2.4 million and $4.8 million, respectively, which were recorded to electricity sales on the consolidated statements of operations.
Financial Instruments Not Measured at Fair Value
The following table presents the carrying amount and fair value and the fair value hierarchy of the Company’s financial liabilities that are not measured at fair value in the consolidated balance sheets, but for which fair value is disclosed (in thousands):
 
 
 
Fair Value
 
As reflected on the balance sheet
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2017
 
 
 
 
 
 
 
 
 
Long-term debt, including current portion
$
1,720,395

 
$

 
$
1,733,294

 
$

 
$
1,733,294

December 31, 2016
 
 
 
 
 
 
 
 
 
Long-term debt, including current portion
$
1,383,672

 
$

 
$
1,382,038

 
$

 
$
1,382,038

Long-term debt is presented on the consolidated balance sheets, net of financing costs, discounts and premiums. The fair value of variable interest rate long-term debt is approximated by its carrying cost. The fair value of fixed interest rate long-term debt is estimated based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied, using the net present value of cash flow streams over the term using estimated market rates for similar instruments and remaining terms.
10.    Stockholders' Equity
Common Stock
On May 9, 2016, the Company entered into an Equity Distribution Agreement with RBC Capital Markets, LLC, KeyBanc Capital Markets Inc. and Morgan Stanley & Co. LLC (collectively, the Agents). Pursuant to the terms of the Equity Distribution Agreement, the Company may offer and sell shares of the Company’s Class A common stock, par value $0.01 per share, from time to time through the Agents, as the Company’s sales agents for the offer and sale of the shares, up to an aggregate sales price of $200.0 million. The Company intends to use the net proceeds from the sale of the shares for general corporate purposes, which may include the repayment of indebtedness and the funding of acquisitions and investments. For the three months ended March 31, 2017, the Company did not sell any shares under the Equity Distribution Agreement. As of March 31, 2017, approximately $170.8 million in aggregate offering price remained available to be sold under the agreement.

25


Dividends
The following table presents cash dividends declared on Class A common stock for the periods presented:
 
Dividends
Per Share
 
Declaration Date
 
Record Date
 
Payment Date
2017:
 
 
 
 
 
 
 
First Quarter
$
0.4138

 
February 24, 2017
 
March 31, 2017
 
April 28, 2017
Noncontrolling Interests
The following table presents the balances for noncontrolling interests by project (in thousands):
 
March 31,
 
December 31,
 
2017
 
2016
El Arrayán
$
31,807

 
$
32,237

Logan's Gap
178,605

 
180,092

Panhandle 1
186,864

 
190,415

Panhandle 2
173,063

 
170,139

Post Rock
175,385

 
178,676

Amazon Wind Farm Fowler Ridge
139,828

 
139,687

Noncontrolling interest
$
885,552

 
$
891,246

The following table presents the components of total noncontrolling interest as reported in stockholders’ equity and the consolidated balance sheets (in thousands):
 
Capital
 
Accumulated Loss
 
Accumulated Other Comprehensive Loss
 
Noncontrolling Interest
Balances at December 31, 2015
$
972,241

 
$
(27,426
)
 
$
(553
)
 
$
944,262

Distributions to noncontrolling interests
(3,917
)
 

 

 
(3,917
)
Other
(465
)
 

 

 
(465
)
Net loss

 
(5,378
)
 

 
(5,378
)
Other comprehensive income, net of tax

 

 
(800
)
 
(800
)
Balances at March 31, 2016
$
967,859

 
$
(32,804
)
 
$
(1,353
)
 
$
933,702

 
 
 
 
 
 
 
 
Balances at December 31, 2016
$
954,242

 
$
(62,614
)
 
$
(382
)
 
$
891,246

Distributions to noncontrolling interests
(2,647
)
 

 

 
(2,647
)
Net loss

 
(3,114
)
 

 
(3,114
)
Other comprehensive income, net of tax

 

 
67

 
67

Balances at March 31, 2017
$
951,595

 
$
(65,728
)
 
$
(315
)
 
$
885,552

11.    Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the reportable period. Diluted earnings (loss) per share is computed by adjusting basic earnings (loss) per share for the effect of all potential common shares unless they are anti-dilutive. For purpose of this calculation, potentially dilutive securities are determined by applying the treasury stock method to the assumed exercise of in-the-money stock options and the assumed vesting of outstanding restricted stock awards (RSAs) and release of deferred restricted stock units (RSUs). Potentially dilutive securities related to convertible senior notes are determined using the if-converted method.
The Company's vested deferred RSUs have non-forfeitable rights to dividends prior to release and are considered participating securities. Accordingly, they are included in the computation of basic and diluted loss per share, pursuant to the two-class method. Under the two-class method, distributed and undistributed earnings allocated to participating securities are excluded from net

26


earnings (loss) attributable to common stockholders for purposes of calculating basic and diluted earnings (loss) per share. However, net losses are not allocated to participating securities since they are not contractually obligated to share in the losses of the Company.
For the three months ended March 31, 2017 and 2016, the Company excluded 8.0 million and 8.0 million, respectively, of potentially dilutive securities from the diluted earnings (loss) per share calculation as their effect is anti-dilutive.
The computations for Class A basic and diluted loss per share are as follows (in thousands except share data):
 
Three months ended March 31,
 
2017
 
2016
Numerator for basic and diluted loss per share:
 
 
 
Net earnings (loss) attributable to Pattern Energy
$
5,653

 
$
(23,670
)
Less: earnings allocated to participating securities
(23
)
 
(10
)
Net earnings (loss) attributable to common stockholders
$
5,630

 
$
(23,680
)
 
 
 
 
Denominator for earnings (loss) per share:
 
 
 
Weighted average number of shares:
 
 
 
Class A common stock - basic
87,062,612

 
74,437,998

Add dilutive effect of:
 
 
 
Restricted stock awards
57,759

 

Restricted stock units
10,909

 

Class A common stock - diluted
87,131,280

 
74,437,998

 
 
 
 
Earnings (loss) per share:
 
 
 
Class A common stock:
 
 
 
Basic and diluted
$
0.06

 
$
(0.32
)
 
 
 
 
Dividends declared per Class A common share
$
0.41

 
$
0.38


12.    Commitments and Contingencies
Commitments
Service and maintenance agreement
In March 2017, the Company entered into revised Long-term Service Agreements (LTSAs) at certain of its projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but the Company has become responsible for a portion of the maintenance and repairs, including on major component parts. The following table presents the reduction in fixed contract commitments, from that disclosed in the Company's 2016 Form 10-K, as a result of the revised LTSAs and payments made during the period.
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
Service and maintenance agreements December 31, 2016
$53,534
 
$40,908
 
$34,206
 
$31,374
 
$31,983
 
$118,198
 
$310,203
Payments as of March 31, 2017
(13,507
)
 

 

 

 

 

 
(13,507
)
Change in service and maintenance agreements
(11,886
)
 
(12,228
)
 
(12,084
)
 
(11,950
)
 
(12,190
)
 
(41,877
)
 
(102,215
)
Service and maintenance agreements as of March 31, 2017
$
28,141

 
$
28,680

 
$
22,122

 
$
19,424

 
$
19,793

 
$
76,321

 
$
194,481


27


Letters of Credit
Power Sale Agreements
The Company owns and operates wind power projects, and has entered into various long-term power sale agreements that terminate from 2019 to 2039. The terms of these agreements generally provide for the annual delivery of a minimum amount of electricity at fixed prices and in some cases include price escalation over the term of the agreement. Under the terms of these agreements, as of March 31, 2017, the Company issued irrevocable letters of credits to guarantee its performance for the duration of the agreements totaling $107.0 million.
Project Finance and Lease Agreements
The Company has various project finance and lease agreements which obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of March 31, 2017, the Company issued irrevocable letters of credit totaling $105.0 million which includes letters of credit issued under the Revolving Credit Facility to ensure performance under the various project finance and lease agreements.
Contingencies
Turbine Operating Warranties and Service Guarantees
The Company has various turbine availability warranties from its turbine manufacturers and service guarantees from its service and maintenance providers. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee measurement period, the service provider is obligated to pay, as liquidated damages at the end of the warranty measurement period, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee measurement period, the Company has an obligation to pay a bonus to the service provider at the end of the warranty measurement period. As of March 31, 2017, the Company recorded liabilities of $1.9 million associated with bonuses payable to the turbine manufacturers and service providers.
Legal Matters
From time to time, the Company has become involved in claims and legal matters arising in the ordinary course of business. Management is not currently aware of any matters that will have a material adverse effect on the financial position, results of operations, or cash flows of the Company.
Indemnity
The Company provides a variety of indemnities in the ordinary course of business to contractual counterparties and to its lenders and other financial partners. The Company is party to certain indemnities for the benefit of project finance lenders and tax equity partners of certain projects. These consist principally of indemnities that protect the project finance lenders from, among other things, the potential effect of any recapture by the U.S. Department of the Treasury of any amount of the Cash Grants previously received by the projects and eligibility of production tax credits and certain legal matters, limited to the amount of certain related costs and expenses.
13.    Related Party Transactions
Management Fees
The Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand, K2, and Armow, in addition to various Pattern Development 1.0 subsidiaries and equity method investments. The Company reclassified its presentation of management service fees received from related party revenue, as disclosed in prior periods, to other revenue on the consolidated statements of operations.

28


Management Services Agreement and Shared Management
The Company has entered into a Multilateral Management Services Agreement (MSA) with the Pattern Development Companies, which provides for the Company and the Pattern Development Companies to benefit, primarily on a cost-reimbursement basis, from the parties’ respective management and other professional, technical and administrative personnel, all of whom report to the Company’s executive officers. Costs and expenses incurred at the Pattern Development Companies or their respective subsidiaries on the Company's behalf will be allocated to the Company. Conversely, costs and expenses incurred at the Company or its respective subsidiaries on the behalf of a Pattern Development Company will be allocated to the respective Pattern Development Company.
Pursuant to the MSA, certain of the Company’s executive officers, including its Chief Executive Officer (shared PEG executives), also serve as executive officers of the Pattern Development Companies and devote their time to both the Company and the Pattern Development Companies as is prudent in carrying out their executive responsibilities and fiduciary duties. The shared PEG executives have responsibilities for both the Company and the respective Pattern Development Companies and, as a result, these individuals do not devote all of their time to the Company’s business. Under the terms of the MSA, each of the respective Pattern Development Companies is required to reimburse the Company for an allocation of the compensation paid to such shared PEG executives reflecting the percentage of time spent providing services to such Pattern Development Company. The Company reclassified its presentation of related party receivables and payables as disclosed in prior periods to be presented within other current assets and other current liabilities on the consolidated balance sheets, respectively. In addition, the Company reclassified its presentation of reimbursements received by the Pattern Development Companies under the MSA from related party income, as disclosed in prior periods, to a reduction to general and administrative expense on the consolidated statements of operations. The MSA costs incurred by the company are included in related party general and administrative on the consolidated statements of operations.
Related Party Transactions
The table below presents amounts due from and to related parties as included in the consolidated balance sheets for the following periods (in millions):
 
March 31, 2017
 
December 31, 2016
Other current assets:
 
 
 
Amounts due from Pattern Development 1.0
$
1.0

 
$
0.4

Amounts due from Pattern Development 2.0
0.5

 
0.2

Amounts due from unconsolidated investments
0.6

 
0.5

Total due from related parties
$
2.1

 
$
1.1

 
 
 
 
Other current liabilities:
 
 
 
Amounts due to Pattern Development 1.0
$
2.2

 
$
1.3

Total due to related parties
$
2.2

 
$
1.3

The table below presents revenue, reimbursement and (expenses) recognized for management fees and the MSA, as included in the statements of operations for the following periods (in thousands):
 
 
 
 
Three months ended March 31,
Related Party Agreement
 
Financial Statement Line Item
 
2017
 
2016
Management fees
 
Other revenue
 
$
2,224

 
$
1,215

MSA reimbursement
 
General and administrative
 
$
1,791

 
$
1,007

MSA costs
 
Related party general and administrative expense
 
$
(3,426
)
 
$
(1,897
)

29


14.    Subsequent Events
On May 4, 2017, the Company declared an increased dividend for the first quarter, payable on July 31, 2017, to holders of record on June 30, 2017, in the amount of $0.4180 per Class A share, or $1.672 on an annualized basis. This is a 1.0% increase from the first quarter of 2017.
On April 21, 2017, the Company acquired an 84% initial cash flow interest in Broadview and 99% ownership interest in Western Interconnect from Pattern Development 1.0. The total purchase consideration of $269 million included $215 million of cash paid at closing and $54 million of Western Interconnect construction debt which was converted to term debt immediately after the acquisition. The Grady project is a wind project on the identified ROFO list being separately developed by Pattern Development 2.0 which is expected to begin full construction not earlier than 2018, and which intends to interconnect through Western Interconnect. Following the commencement of commercial operations of the Grady project, at which time the Grady project will begin making transmission service payments to Western Interconnect, the Company will make a further contingent post-closing payment which is currently estimated to be approximately $18.3 million.


30


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations 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, 2016 and our unaudited consolidated financial statements for the three months ended March 31, 2017 and other disclosures (including the disclosures under “Part II. Item 1A. Risk Factors”) included in this Quarterly Report on Form 10-Q. Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles and are presented in U.S. dollars. Unless the context provides otherwise, references herein to “we,” “our,” “us,” “our company” and “Pattern Energy” refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries.
Overview
We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We hold interests in 18 wind power projects, including Broadview which we acquired in April 2017, located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 2,644 MW. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price or variable price power sale agreement (PPA). Ninety-one percent of the electricity to be generated by our projects will be sold under our power sale agreements which have a weighted average remaining contract life of approximately 14 years as of March 31, 2017.
We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around three core values of creative energy and spirit, pride of ownership and follow-through, and a team first attitude, which guide us in creating a safe, high-integrity work environment, applying rigorous analysis to all aspects of our business, and proactively working with our stakeholders to address environmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our stockholders, are to produce stable and sustainable cash available for distribution, selectively grow our project portfolio and our dividend per Class A share and maintain a strong balance sheet and flexible capital structure.
Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development Companies and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. The Pattern Development Companies (Pattern Energy Group LP (Pattern Development 1.0), Pattern Energy Group 2 LP (Pattern Development 2.0) and their respective subsidiaries (other than us and our subsidiaries)) are leading developers of renewable energy and transmission projects. Our continuing relationship with the Pattern Development Companies provides us with access to a pipeline of acquisition opportunities. Currently, Pattern Development Companies have a 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development Companies and third parties capitalizing on the large fragmented global renewable energy market. Our business is primarily focused in the U.S., Canada and Chile; however, we expect opportunities in Japan and Mexico will form part of our growth strategy.
The discussion and analysis below has been organized as follows:
Recent Developments
Key Metrics
Results of Operations
Liquidity and Capital Resources
Sources of Liquidity
Uses of Liquidity
Critical Accounting Policies and Estimates


31


Recent Developments
On April 21, 2017, we acquired an 84% initial cash flow interest in Broadview and 99% ownership interest in Western Interconnect from Pattern Development 1.0. The total purchase consideration of $269 million included $215 million of cash paid at closing and $54 million of Western Interconnect construction debt which was converted to term debt immediately after the acquisition. The Grady project is a wind project on the identified ROFO list being separately developed by Pattern Development 2.0 which is expected to begin full construction not earlier than 2018, and which intends to interconnect through Western Interconnect. Following the commencement of commercial operations of the Grady project, at which time the Grady project will begin making transmission service payments to Western Interconnect, the Company will make a further contingent post-closing payment which is currently estimated to be approximately $18.3 million.
In March 2017, we entered into revised Long-term Service Agreements (LTSAs) at certain of our projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but we have become responsible for a portion of the maintenance and repairs, including on major component parts. The revised LTSAs reduce fixed contract commitments by approximately $102.2 million over the next 7-10 years.
In January 2017, we issued unsecured senior notes with an aggregate principal amount of $350.0 million (the Unsecured Senior Notes). Net proceeds to us were approximately $345.0 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. We used approximately $215 million of the net proceeds to partially fund our acquisition of the Broadview projects and used $128 million of proceeds to repay borrowings incurred under the Revolving Credit Facility to finance the purchase of the Armow project. The Unsecured Senior Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The Unsecured Senior Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of our subsidiaries.
Below is a summary of our Identified Right of First Offer Projects that we expect to acquire from the Pattern Development Companies in connection with our respective purchase rights.
 
 
 
 
 
 
 
 
 
 
 
 
Capacity (MW)
Identified
ROFO Projects
 
Status
 
Location
 
Construction
Start
 (1)
 
Commercial
Operations 
(2)
 
Contract
Type
 
Rated (3)
 
Pattern
Development-
Owned
(4)
Pattern Development 1.0 Projects
 
 
 
 
 
 
 
 
 
 
 
 
Kanagi Solar
 
Operational
 
Japan
 
2014
 
2016
 
PPA
 
14
 
6
Futtsu Solar
 
Operational
 
Japan
 
2014
 
2016
 
PPA
 
42
 
19
Conejo Solar(5)
 
Operational
 
Chile
 
2015
 
2016
 
PPA
 
104
 
104
Meikle
 
Operational
 
British Columbia
 
2015
 
2017
 
PPA
 
180
 
180
Belle River
 
In construction
 
Ontario
 
2016
 
2017
 
PPA
 
100
 
43
Ohorayama
 
In construction
 
Japan
 
2016
 
2018
 
PPA
 
33
 
31
Mont Sainte-Marguerite
 
In construction
 
Québec
 
2017
 
2017
 
PPA
 
147
 
147
North Kent
 
In construction
 
Ontario
 
2017
 
2018
 
PPA
 
100
 
43
Henvey Inlet
 
Late stage development
 
Ontario
 
2017
 
2018
 
PPA
 
300
 
150
Tsugaru
 
Late stage development
 
Japan
 
2017
 
2020
 
PPA
 
126
 
63
Pattern Development 2.0 Projects
 
 
 
 
 
 
 
 
 
 
 
 
Grady
 
Late stage development
 
New Mexico
 
2018
 
2019
 
PPA
 
220
 
176
 
 
 
 
 
 
 
 
 
 
 
 
1,366
 
962
(1) 
Represents year of actual or anticipated commencement of construction.
(2) 
Represents year of actual or anticipated commencement of commercial operations.
(3) 
Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated will be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.
(4) 
Pattern Development-Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Development 1.0's or Pattern Development 2.0's percentage ownership interest in the distributable cash flow of the project.
(5) 
From time to time, we conduct strategic reviews of our markets. We have been conducting a strategic review of the market, growth, and opportunities in Chile. In the event we believe we can utilize funds that have already been invested in Chile or funds that might otherwise be invested in Chile in a more productive manner elsewhere that could generate a higher return on investment, we may decide to exit Chile for other opportunities with greater potential. In addition, Pattern Development 1.0 is also concurrently exploring strategic alternatives for its assets in Chile.

32



Key Metrics
We regularly review a number of financial measurements and operating metrics to evaluate our performance, measure our growth and make strategic decisions. In addition to traditional U.S. GAAP performance and liquidity measures, such as total revenue, cost of revenue, net income (loss) and net cash provided by operating activities, we also consider cash available for distribution as a supplemental liquidity measure and Adjusted EBITDA, MWh sold and average realized electricity price in evaluating our operating performance. We disclose cash available for distribution, which is a non-U.S. GAAP measure, because management recognizes that it will be used as a supplemental measure by investors and analysts to evaluate our liquidity. We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operating performance. Each of these key metrics is discussed below.
Limitations to Key Metrics
We disclose cash available for distribution because management recognizes that it will be used as a supplemental measure by investors and analysts to evaluate our liquidity. However, cash available for distribution has limitations as an analytical tool because it excludes depreciation, amortization and accretion, does not capture the level of capital expenditures necessary to maintain the operating performance of our projects, is not reduced for principal payments on our project indebtedness except to the extent they are paid from operating cash flows during a period, and excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results from operations. Cash available for distribution is a non-U.S. GAAP measure and should not be considered an alternative to net cash provided by operating activities or any other liquidity measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculation of cash available for distribution is not necessarily comparable to cash available for distribution as calculated by other companies.
We disclose Adjusted EBITDA, which is a non-U.S. GAAP measure, because management believes this metric assists investors and analysts in comparing our operating performance across reporting periods on a consistent basis by excluding items that our management believes are not indicative of our core operating performance. We use Adjusted EBITDA to evaluate our operating performance. You should not consider Adjusted EBITDA as an alternative to net income (loss), determined in accordance with U.S. GAAP.
Adjusted EBITDA has limitations as an analytical tool. Some of these limitations are:
Adjusted EBITDA
does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
does not reflect changes in, or cash requirements for, our working capital needs;
does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt, or our proportional interest in the interest expense of our unconsolidated investments or the cash requirements necessary to service interest or principal payments on the debt borne by our unconsolidated investments;
does not reflect our income taxes or the cash requirement to pay our taxes; or our proportional interest in income taxes of our unconsolidated investments or the cash requirements necessary to pay the taxes of our unconsolidated investments;
does not reflect depreciation, amortization and accretion which are non-cash charges; or our proportional interest in depreciation, amortization and accretion of our unconsolidated investments. The assets being depreciated, amortized and accreted will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and
does not reflect the effect of certain mark-to-market adjustments and non-recurring items or our proportional interest in the mark-to-market adjustments at our unconsolidated investments.
We do not have control, nor have any legal claim to the portion of the unconsolidated investees' revenues and expenses allocable to our joint venture partners. As we do not control, but do exercise significant influence, we account for the unconsolidated investments in accordance with the equity method of accounting. Net earnings from these investments are reflected within our consolidated statements of operations in "Earnings in unconsolidated investments, net." Adjustments related to our proportionate share from unconsolidated investments include only our proportionate amounts

33


of interest expense, income taxes, depreciation, amortization and accretion, and mark-to-market adjustments included in "Earnings in unconsolidated investments, net;" and
Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered in isolation or as a substitute for performance measures calculated in accordance with U.S. GAAP.
Cash Available for Distribution
We define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with our operations. It is a non-U.S. GAAP measure of our ability to generate cash to service our dividends.
Cash available for distribution represents cash provided by operating activities as adjusted to (i) add or subtract changes in operating assets and liabilities, (ii) subtract net deposits into restricted cash accounts, which are required pursuant to the cash reserve requirements of financing agreements, to the extent they are paid from operating cash flows during a period, (iii) subtract cash distributions paid to noncontrolling interests, (iv) subtract scheduled project-level debt repayments in accordance with the related loan amortization schedule, to the extent they are paid from operating cash flows during a period, (v) subtract non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period, (vi) add cash distributions received from unconsolidated investments, to the extent such distributions were derived from operating cash flows and (vii) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.
The most directly comparable U.S. GAAP measure to cash available for distribution is net cash provided by operating activities. The following table is a reconciliation of our net cash provided by operating activities to cash available for distribution for the periods presented (unaudited and in thousands):
 
Three months ended March 31,
 
2017
 
2016
Net cash provided by operating activities
$
43,752

 
$
14,721

Changes in operating assets and liabilities
13,423

 
18,967

Network upgrade reimbursement
317

 

Release of restricted cash to fund project and general and administrative costs

 
590

Operations and maintenance capital expenditures
(146
)
 
(230
)
Distributions from unconsolidated investments
4,205

 
19,814

Other
(3,432
)
 
13

Less:
 
 
 
Distributions to noncontrolling interests
(2,647
)
 
(3,917
)
Principal payments paid from operating cash flows
(10,326
)
 
(8,943
)
Cash available for distribution
$
45,146

 
$
41,015

Cash available for distribution was $45.1 million for the three months ended March 31, 2017 as compared to $41.0 million for the same period in the prior year. This $4.1 million increase in cash available for distribution was primarily due to a $10.7 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs), a $3.1 million decrease in project expense, a $1.3 million decrease in distribution to noncontrolling interests, and a $0.9 million increase in total distributions from unconsolidated investment, as reported in operating and investing activities on the consolidated statements of cash flows. These increases to cash available for distribution were offset by a $4.1 million increase in operating expense, a $3.5 million project reserve funding, a $2.0 million increase in interest expense, and a $1.4 million increase in principal payments.

34


Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) before net interest expense, income taxes, and depreciation, amortization and accretion, including our proportionate share of net interest expense, income taxes, and depreciation, amortization and accretion of unconsolidated investments. Adjusted EBITDA also excludes the effect of certain mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt, realized derivative gain or loss from refinancing transactions, gain or loss related to acquisitions or divestitures, and adjustments from unconsolidated investments. In calculating Adjusted EBITDA, we exclude mark-to-market adjustments to the value of our derivatives because we believe that it is useful for investors to understand, as a supplement to net income (loss) and other traditional measures of operating results, the results of our operations without regard to periodic, and sometimes material, fluctuations in the market value of such assets or liabilities.
Adjustments from unconsolidated investments represent distributions received in excess of the carrying amount of our investment, as a result of a suspension of recognition of equity method earnings during the three months ended March 31, 2016. During the three months ended March 31, 2017, none of our unconsolidated investments were in suspension. As discussed in Note 2, Summary of Significant Accounting Policies in our 2016 Form-10K, we may suspend the recognition of equity method earnings when we receive distributions in excess of the carrying value of our investment, and we are not liable for the obligations of the investee nor otherwise committed to provide financial support, we recognize such excess distributions as equity method earnings in the period the distributions occur. Additionally, when our carrying value in an unconsolidated investment is zero and we are not liable for the obligations of the investee nor otherwise committed to provide financial support, we will not recognize equity in earnings (losses) or equity in other comprehensive income of unconsolidated investments.
The most directly comparable U.S. GAAP measure to Adjusted EBITDA is net income (loss). The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented (unaudited and in thousands):
 
Three months ended March 31,
 
2017
 
2016
Net income (loss)
$
2,539

 
$
(29,048
)
Plus:
 
 
 
Interest expense, net of interest income
22,061

 
20,315

Tax provision
4,775

 
1,298

Depreciation, amortization and accretion
47,227

 
45,384

EBITDA
76,602

 
37,949

Unrealized loss on energy derivative (1)
2,358

 
4,825

Loss on undesignated derivatives, net
648

 
13,631

Net (gain) loss on transactions
312

 
(33
)
Adjustments from unconsolidated investments (2)

 
(1,712
)
Plus, proportionate share from unconsolidated investments:
 
 
 
Interest expense, net of interest income
9,340

 
7,219

Depreciation, amortization and accretion
8,454

 
6,293

Loss on undesignated derivatives, net
484

 
9,916

Adjusted EBITDA
$
98,198

 
$
78,088

(1)
Amount is included in electricity sales on the consolidated statements of operations.
(2) 
See Note 5. Unconsolidated Investments in the Notes to Consolidated Financial Statements in this Form 10-Q, for further discussion.
Adjusted EBITDA for the three months ended March 31, 2017 was $98.2 million compared to $78.1 million for the same period in the prior year, an increase of $20.1 million, or approximately 25.8%. The increase in Adjusted EBITDA for the three months ended March 31, 2017 as compared to the same period in the prior year was primarily due to a $10.7 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs), a $9.6 million increase in our proportionate share of Adjusted EBITDA from unconsolidated investments, and a $3.1 million decrease in project expense. The increase to Adjusted EBITDA was partially offset by an increase to operating expense of $4.1 million.

35


MWh Sold and Average Realized Electricity Price
The number of consolidated MWh, unconsolidated investments proportional MWh and proportional MWh sold, as well as consolidated average realized price per MWh and the proportional average realized price per MWh sold, are the operating metrics that help explain trends in our revenue, earnings from our unconsolidated investments and net income (loss) attributable to us.
Consolidated MWh sold for any period presented, represents 100% of MWh sold by wholly-owned and partially-owned subsidiaries in which we have a controlling interest and are consolidated in our consolidated financial statements;
Noncontrolling interest MWh represents that portion of partially-owned subsidiaries not attributable to us;
Controlling interest in consolidated MWh is the difference between the consolidated MWh sold and the noncontrolling interest MWh;
Unconsolidated investments proportional MWh is our proportion in MWh sold from our equity method investments;
Proportional MWh sold for any period presented, represents the sum of the controlling interest and our percentage interest in our unconsolidated investments; and
Average realized electricity price for each of consolidated MWh sold, unconsolidated investments proportional MWh sold and proportional MWh sold represents (i) total revenue from electricity sales for each of the respective MWh sold, discussed above, excluding unrealized gains and losses on our energy derivative and the amortization of finite-lived intangible assets and liabilities, divided by (ii) the respective MWh sold.
The following table presents selected operating performance metrics for the periods presented (unaudited):
 
 
Three months ended March 31,
 
 
 
 
MWh sold
 
2017
 
2016
 
Change
 
% Change
Consolidated MWh sold
 
1,914,259

 
1,783,413

 
130,846

 
7.3
 %
Less: noncontrolling MWh
 
(259,594
)
 
(262,045
)
 
2,451

 
(0.9
)%
Controlling interest in consolidated MWh
 
1,654,665

 
1,521,368

 
133,297

 
8.8
 %
Unconsolidated investments proportional MWh
 
383,494

 
279,666

 
103,828

 
37.1
 %
Proportional MWh sold
 
2,038,159

 
1,801,034

 
237,125

 
13.2
 %
 
 
 
 
 
 
 
 
 
Average realized electricity price per MWh
 
 
 
 
 
 
 
 
Consolidated average realized electricity price per MWh
 
$
53

 
$
51

 
$
2

 
3.9
 %
Unconsolidated investments proportional average realized electricity price per MWh
 
$
115

 
$
108

 
$
7

 
6.5
 %
Proportional average realized electricity price per MWh
 
$
67

 
$
63

 
$
4

 
6.3
 %
Our consolidated MWh sold for the three months ended March 31, 2017 was 1,914,259 MWh, as compared to 1,783,413 MWh for the three months ended March 31, 2016, an increase of 130,846 MWh, or 7.3%. The increase in consolidated MWh sold was primarily attributable to less favorable wind conditions in the first quarter 2016 compared to the current period.
Our proportional MWh sold for the three months ended March 31, 2017 was 2,038,159 MWh, as compared to 1,801,034 MWh for the three months ended March 31, 2016, an increase of 237,125 MWh, or 13.2%. The change in proportional MWh sold was primarily attributable to:
an increase in volume of 133,297 MWh from controlling interest in consolidated MWh; and
an increase in volume of 103,828 MWh from unconsolidated investments due to the acquisition of Armow in the fourth quarter 2016.
Our consolidated average realized electricity price was $53 per MWh for the three months ended March 31, 2017, as compared to $51 per MWh for the three months ended March 31, 2016. The increase of $2 per MWh was primarily due to an increase in volume of higher priced PPAs and revenue earned from renewable energy credits.
Our proportional average realized electricity price was $67 per MWh for the three months ended March 31, 2017, as compared to $63 per MWh for the three months ended March 31, 2016. The $4 per MWh increase in the proportional average realized

36


electricity price was primarily due to the impact of foreign exchange on revenue denominated in the Canadian dollar at our Canadian projects, an increase in volume from higher priced PPAs and revenue earned from renewable energy credits.

Results of Operations
The following table and discussion provide selected financial information for the periods presented and is unaudited (in thousands, except percentages):
 
Three months ended March 31,
 
2017
 
2016
 
$ Change
 
% Change
Revenue
$
100,833

 
$
87,639

 
$
13,194

 
15.1
 %
Total cost of revenue
72,910

 
75,657

 
(2,747
)
 
(3.6
)%
Total operating expenses
14,550

 
10,459

 
4,091

 
39.1
 %
Total other expense
6,059

 
29,273

 
(23,214
)

(79.3
)%
Net income (loss) before income tax
7,314

 
(27,750
)
 
35,064

 
(126.4
)%
Tax provision
4,775

 
1,298

 
3,477

 
267.9
 %
Net income (loss)
2,539

 
(29,048
)
 
31,587

 
(108.7
)%
Net loss attributable to noncontrolling interest
(3,114
)
 
(5,378
)
 
2,264

 
(42.1
)%
Net income (loss) attributable to Pattern Energy
$
5,653

 
$
(23,670
)
 
$
29,323

 
(123.9
)%
Total revenue
Total revenue for the three months ended March 31, 2017 was $100.8 million compared to $87.6 million for the three months ended March 31, 2016, an increase of $13.2 million, or approximately 15.1%. The increase was primarily attributable to $10.3 million in additional electricity sales primarily due to an increase in volume due to less favorable wind conditions in the first quarter 2016 compared to the current period and a $2.5 million decrease in unrealized losses primarily due to a larger decrease in the change in the forward gas price curves when compared to the prior period.
Cost of revenue
Cost of revenue for the three months ended March 31, 2017 was $72.9 million compared to $75.7 million for the three months ended March 31, 2016, a decrease of $2.7 million, or approximately 3.6%. The decrease was primarily attributable to a $2.5 million decrease in turbine operations and maintenance expense.
Operating expenses
Operating expenses for the three months ended March 31, 2017 were $14.6 million compared to $10.5 million for the three months ended March 31, 2016, an increase of $4.1 million, or approximately 39.1%. The increase in operating expenses was primarily attributable to a $2.1 million increase in consulting, legal and audit fees related to control remediation efforts, a $1.5 million increase in related party expenses and a $0.8 million increase in employee related expenses.
Other expense
Other expense for the three months ended March 31, 2017 was $6.1 million compared to $29.3 million for the three months ended March 31, 2016, a decrease of $23.2 million, or approximately 79.3%. The change was primarily attributable to:
a $13.0 million increase in earnings in unconsolidated investments, net due to increased project income primarily due to the acquisition of Armow in the fourth quarter 2016, increased wind production and decreases in unrealized losses in undesignated derivatives; and
a $13.0 million decrease in loss on undesignated derivatives, net primarily due to losses incurred in the first quarter 2016 due to decreases in the LIBOR during that period.
The decrease in other expense was partially offset by an increase in interest expense of $1.5 million, primarily due to the issuance of the Unsecured Senior Notes.

37


Tax provision
The tax provision was $4.8 million for the three months ended March 31, 2017 compared $1.3 million for the three months ended March 31, 2016. The tax provision for the three months ended March 31, 2017 was primarily the result of recording a deferred tax liability on the recognized equity income from operations in unconsolidated investments, tax expense in the U.S. from continuing operations, tax expense in our Canadian and Puerto Rican operations and the foreign withholding taxes on intercompany transactions in certain foreign jurisdictions offset by recognizing a deferred tax asset on the recognized losses in Chile.
Net income (loss)
Net income (loss) for the three months ended March 31, 2017, was $2.5 million compared to $(29.0) million for the same period in the prior year; a change of $31.6 million or 108.7%. The increase in earnings was primarily attributed to:
increased revenues of $13.2 million;
a $23.2 million net decrease in other expense primarily related to an increase in earnings in unconsolidated investments and a decrease in loss on undesignated derivatives, net primarily due to losses incurred in the first quarter of 2016 due to decreases in the LIBOR during that period partially offset by an increase in interest expense due to the issuance of $350 million of Unsecured Senior Notes in January 2017; and
decreased project expense of $3.1 million.
These increases to earnings were partially offset by a $4.1 million increase to operating expense and $3.5 million increase in tax provision.
Noncontrolling interest
The net loss attributable to noncontrolling interest was $3.1 million for the three months ended March 31, 2017 compared to $5.4 million for the three months ended March 31, 2016. The decreased loss of $2.3 million was primarily attributable to decreased allocations of losses to tax equity projects.
Liquidity and Capital Resources
Our business requires substantial capital to fund (i) equity investments in our construction projects, (ii) current operational costs, (iii) debt service payments, (iv) dividends to our stockholders, (v) potential investments in new acquisitions, (vi) modifications to our projects, (vii) unforeseen events and (viii) other business expenses. As a part of our liquidity strategy, we plan to retain a portion of our cash flows in above-average wind years in order to have additional liquidity in below-average wind years.
Sources of Liquidity
Our sources of liquidity include cash generated by our operations, cash reserves, borrowings under our corporate and project-level credit agreements and further issuances of equity and debt securities.
The principal indicators of our liquidity are our unrestricted and restricted cash balances and availability under our Revolving Credit Facility and project level facilities. Our available liquidity is as follows (in millions):
 
 
March 31, 2017
Unrestricted cash
 
$
244.7

Restricted cash
 
25.6

Revolving credit facility availability(1)
 
471.8

Project facilities:
 
 
Post construction use
 
99.3

Total available liquidity
 
$
841.4

(1) 
As of May 5, 2017, the amount available on the Revolving Credit Facility is $411.8 million.
We believe that for the remainder of 2017, we will have sufficient liquid assets, cash flows from operations, and borrowings available under our Revolving Credit Facility to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures for at least the next 24 months, not including capital required for additional project

38


acquisitions. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corresponding adverse effect on our borrowing capacity.
In connection with our future capital expenditures and other investments, including any project acquisitions that we may make, we may, from time to time, issue debt or equity securities. Our ability to access the debt and equity markets is dependent on, among other factors, the overall state of the debt and equity markets and investor appetite for investment in clean energy projects in general and our Class A shares in particular. Volatility in the market price of our Class A shares may prevent or limit our ability to utilize our equity securities as a source of capital to help fund acquisitions. An inability to obtain debt or equity financing on commercially reasonable terms could significantly limit our timing and ability to consummate future acquisitions, and to effectuate our growth strategy.
In January 2017, we issued the Unsecured Senior Notes with an aggregate principal amount of $350.0 million. Net proceeds to us were approximately $345.0 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. We used approximately $215 million of the net proceeds to partially fund our acquisition of the Broadview projects and used $128 million of proceeds to repay borrowings incurred under the Revolving Credit Facility to finance the purchase of the Armow project. The Unsecured Senior Notes bear interest at a rate of 5.875% per year, payable semiannually in arrears on February 1 and August 1, beginning on August 1, 2017 and maturing on February 1, 2024, unless repurchased or redeemed at an earlier date. The Unsecured Senior Notes are guaranteed on a senior unsecured basis by Pattern US Finance Company, one of our subsidiaries.
On May 9, 2016, we entered into an Equity Distribution Agreement with RBC Capital Markets, LLC, KeyBanc Capital Markets Inc. and Morgan Stanley & Co. LLC (collectively, the “Agents”). Pursuant to the terms of the Equity Distribution Agreement, we may offer and sell shares of our Class A common stock, par value $0.01 per share, from time to time through the Agents, as our sales agents for the offer and sale of the shares, up to an aggregate sales price of $200 million. We intend to use the net proceeds from the sale of the shares for general corporate purposes, which may include the repayment of indebtedness and the funding of acquisitions and investments. For the three months ended March 31, 2017, we did not sell any shares under the Equity Distribution Agreement. As of March 31, 2017, approximately $170.8 million in aggregate offering price remained available to be sold under the agreement.
Subject to market conditions, we will continue to consider various forms of repricings, refinancings, and/or repayments of our project level finance facilities. No assurances, however, can be given that we will be able to consummate any such transactions, the transactions can be consummated on terms that are financially favorable to us, or that such transactions will have the intended financial effects of improving the consolidated statements of operations, net cash provided by operating activities, or cash available for distribution.
Cash Flows
We use traditional measures of cash flow, including net cash provided by operating activities, net cash used in investing activities and net cash provided by financing activities, as well as cash available for distribution discussed earlier, to evaluate our periodic cash flow results. Below is a summary of our cash flows for each period (in millions):
 
Three months ended March 31,
 
2017
 
2016
Net cash provided by operating activities
$
43.8

 
$
14.7

Net cash provided by (used in) investing activities
2.7

 
(4.4
)
Net cash provided by (used in) financing activities
114.5

 
(40.7
)
Effect of exchange rate changes on cash, cash equivalents and restricted cash

 
1.8

Net change in cash, cash equivalents and restricted cash
$
160.9

 
$
(28.6
)
Net cash provided by operating activities
Net cash provided by operating activities was $43.8 million for the three months ended March 31, 2017 as compared to $14.7 million in the prior year, an increase of $29.0 million, or approximately 197.2%. The increase in cash provided by operating activities was primarily due to higher revenues of $10.7 million (excluding unrealized loss on energy derivative and amortization of PPAs), increased distributions from unconsolidated investments of $16.5 million and decreased project expenses of $3.1 million. These increases were partially offset by increases of $4.1 million in operating expenses.

39


Net cash provided by (used in) investing activities
Net cash provided by investing activities was $2.7 million for the three months ended March 31, 2017, which consisted primarily of distributions from unconsolidated investments of $4.2 million, offset by $1.3 million for capital expenditures and $0.3 million in costs associated with the acquisition of an unconsolidated investment in the fourth quarter of 2016.
Net cash used in investing activities was $4.4 million for the three months ended March 31, 2016, which consisted primarily of $24.1 million for capital expenditures including $18.0 million related to payments for a project that became commercially operable in the fourth quarter of 2015. Net cash used in financing activities was partially offset by $19.8 million in distributions received from unconsolidated investments.
Net cash provided by (used in) financing activities
Net cash provided by financing activities for the three months ended March 31, 2017 was $114.5 million. Net cash provided by financing activities consisted primarily of $350.0 million in proceeds from the issuance of the Unsecured Senior Notes, as discussed previously.
Net cash provided by financing activities was partially offset by:
$180.0 million in repayments of the Revolving Credit Facility;
$35.5 million of dividend payments;
$10.3 million in repayment of long-term debt;
$5.0 million in payments for deferred financing costs associated with the issuance of the Unsecured Senior Notes; and
$2.6 million in distributions to noncontrolling interests.
Net cash used by financing activities for the three months ended March 31, 2016 was $40.7 million. Net cash used by financing activities consisted primarily of the following:
$27.7 million of dividend payments;
$3.9 million of distributions to noncontrolling interests; and
$8.9 million in repayments of debt.
Uses of Liquidity
Cash Dividends to Investors
We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A common stock. On May 4, 2017, we increased our dividend to $0.4180 per share, or $1.672 per share on an annualized basis, commencing with respect to dividends to be paid on July 31, 2017 to holders of record on June 30, 2017. The following table sets forth the dividends declared on shares of Class A common stock for the periods indicated.
 
Dividends
Per Share
 
Declaration Date
 
Record Date
 
Payment Date
2017:
 
 
 
 
 
 
 
Second Quarter
$
0.4180

 
May 4, 2017
 
June 30, 2017
 
July 31, 2017
First Quarter
$
0.41375

 
February 24, 2017
 
March 31, 2017
 
April 28, 2017
We established our initial quarterly dividend level based on a targeted cash available for distribution payout ratio of 80% after considering the annual cash available for distribution that we expect our projects will be able to generate following the commencement of commercial operations at all of our construction projects and with due regard to retaining a portion of the cash available for distribution to grow our business. We intend to grow our business primarily through the acquisition of operational and construction-ready power projects, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share of Class A common stock over time. We may in the future raise capital and make investments in new power projects upon or near the commencement of construction of such projects and therefore prior to the expected commencement of operations of the new projects, which could result in a passage of time of twelve or more months before we begin to receive any cash flow contributions from such projects to our cash available for distribution. In connection

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with these investments, we may increase our dividends prior to the receipt of such cash flow contributions, which would likely cause our payout ratio to temporarily exceed our targeted run-rate payout ratio. However, the determination of the amount of cash dividends to be paid to holders of our Class A common stock will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. Refer to Item 1A “Risk Factors—Risks Related to Ownership of our Class A Shares—Risks Regarding our Cash Dividend Policy” in our Annual Report on Form 10-K for the year ended December 31, 2016.
We expect to pay a quarterly dividend on or about the 30th day following each fiscal quarter to holders of record of our Class A common stock on the last day of such quarter.
Capital Expenditures and Investments
We expect to make investments in additional projects. As discussed above, on April 21, 2017, we acquired Broadview and Western Interconnect from Pattern Development 1.0. The total purchase consideration of $269 million included $215 million of cash paid at closing and $54 million of Western Interconnect construction debt which was converted to term debt immediately after the acquisition.
We also evaluate, from time to time, third-party acquisition opportunities. We believe that we will have sufficient cash and Revolving Credit Facility capacity to complete the funding of future construction commitments we may have, but this may be affected by any other acquisitions or investments that we make. To the extent that we make any such investments or acquisitions, we will evaluate capital markets and other corporate financing sources available to us at the time. In addition, we will make investments from time to time at our operating projects. Operational capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves, although funding for major capital expenditures may be provided by additional project debt or equity. Therefore, the distributions that we receive from the projects may be made net of certain capital expenditures needed at the projects. For the year ending December 31, 2017, we have budgeted $4.4 million for operational capital expenditures and $5.5 million for expansion capital expenditures.
Contractual Obligations
There have been no material changes in our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, except as described below:
Service and Maintenance Agreements
In March 2017, we entered into revised LTSAs at certain of our projects pursuant to which the turbine manufacturer will continue to provide routine and corrective maintenance service, but we have become responsible for a portion of the maintenance and repairs, including on major component parts. The revised LTSAs reduce fixed contract commitments and the following table summarizes the change in future commitments from that disclosed in our 2016 Form 10-K (in thousands):
Contractual Obligations
Less Than
1 Year
 
1-3 Years
 
3-5 Years
 
More Than
5 Years
Total
Service and maintenance agreements December 31, 2016
$
53,534

 
$
75,114

 
$
63,357

 
$
118,198

$
310,203

Payments as of March 31, 2017
(13,507
)
 

 

 

(13,507
)
Change in service and maintenance agreements
(11,886
)
 
(24,312
)
 
(24,140
)
 
(41,877
)
(102,215
)
Service and maintenance agreements as of March 31, 2017
$
28,141

 
$
50,802

 
$
39,217

 
$
76,321

$
194,481

Broadview Transaction
As part of the Broadview Transaction, we became a party to several customary contracts expected for wind energy and transmission companies, such as letter of credit facilities, service and maintenance contracts, transmission service agreements, leases and other commitments.
Off-Balance Sheet Arrangements
As of March 31, 2017, we did not have any significant off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K.

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Credit Agreements for Unconsolidated Investments
Below is a summary of our proportion of debt in unconsolidated investments, as of March 31, 2017 (in thousands):
 
Total
Project Debt
 
Percentage of
Ownership
 
Our Portion of
Unconsolidated
Project Debt
Armow
$
388,564

 
50.0
%
 
$
194,282

South Kent
474,019

 
50.0
%
 
237,010

Grand
272,442

 
45.0
%
 
122,599

K2
579,087

 
33.3
%
 
193,010

Unconsolidated investments - debt
$
1,714,112

 
 
 
$
746,901


Critical Accounting Policies and Estimates
There have been no material changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We have significant exposure to commodity prices, interest rates and foreign currency exchange rates, as described below. To mitigate these market risks, we have entered into multiple derivatives. We have not applied hedge accounting treatment to all of our derivatives, therefore we are required to mark some of our derivatives to market through earnings on a periodic basis, which will result in non-cash adjustments to our earnings and may result in volatility in our earnings, in addition to potential cash settlements for any losses.
Commodity Price Risk
We manage our commodity price risk for electricity sales primarily through the use of fixed price long-term power purchase agreements with creditworthy counterparties. Our financial results reflect approximately 230,676 MWh of electricity sales during the three months ended March 31, 2017 that were subject to spot market pricing. A hypothetical increase or decrease of 10% or $1.27 per MWh in these spot market prices would have increased or decreased revenue by $0.3 million for the three months ended March 31, 2017.
Interest Rate Risk
As of March 31, 2017, our long-term debt includes both fixed and variable rate debt. As long term debt is not carried at fair value on the consolidated balance sheets, changes in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments prior to their maturity. The fair market value of our outstanding convertible senior notes, or "debentures," is subject to interest rate risk, market price risk and other factors due to the convertible feature of the debentures. The fair market value of the debentures will generally increase as interest rates fall and decrease as interest rates rise. In addition, the fair market value of the debentures will generally increase as the market price of our Class A common stock increases and decrease as the market price of our Class A common stock falls. The interest and market value changes affect the fair market value of the debentures, but do not impact our financial position, cash flows or results of operations due to the fixed nature of the debt obligations, except to the extent that changes in the fair value of the debentures or value of Class A common stock permit the holders of the debentures to convert into shares. As of March 31, 2017, the estimated fair value of our debt was $1.7 billion and the carrying value of our debt was $1.7 billion. The fair value of variable interest rate long-term debt is approximated by its carrying cost. A hypothetical increase or decrease in market interest rates by 1% would have resulted in a $51.8 million decrease or $56.1 million increase in the fair value of our fixed rate debt.

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We are exposed to fluctuations in interest rate risk as a result of our variable rate debt and outstanding amounts due under our Revolving Credit Facility. As of March 31, 2017, no amounts were outstanding under the Revolving Credit Facility.
We may use a variety of derivative instruments, with respect to our variable rate debt, to manage our exposure to fluctuations in interest rates, including interest rate swaps. As a result, our interest rate risk is limited to the unhedged portion of the variable rate debt. As of March 31, 2017, the unhedged portion of our variable rate debt was $0.1 million. A hypothetical increase or decrease in interest rates by 1% would not have a material impact to interest expense for the three months ended March 31, 2017.
Foreign Currency Exchange Rate Risk
Our wind power projects are located in the United States, Canada and Chile. As a result, our financial results could be significantly affected by factors such as changes in foreign currency exchange rates or weak economic conditions in the foreign markets in which we operate. When the U.S. dollar strengthens against foreign currencies, the relative value in revenue earned in the respective foreign currency decreases. When the U.S. dollar weakens against foreign currencies, the relative value in revenue earned in the respective foreign currency increases. A majority of our power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. For the three months ended March 31, 2017, our financial results included C$22.2 million, or $16.6 million calculated based on the monthly average exchange rate, in Canadian dollar denominated net income, from our Canadian operations. A hypothetical increase or decrease of 10% in exchange rates between the Canadian and U.S. dollar would have increased or decreased net earnings of our Canadian operations by $1.7 million for the three months ended March 31, 2017.
In January 2015, we established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in our cash flow, which may have an adverse impact to our short-term liquidity or financial condition. For the three months ended March 31, 2017, we recognized an unrealized loss on foreign currency forward contracts of $1.1 million in loss on undesignated derivatives, net in the consolidated statements of operations. We also recognized a realized gain of $0.3 million in loss on undesignated derivatives, net in the consolidated statements of operations related to foreign currency forward contracts that matured during the three months ended March 31, 2017.
As of March 31, 2017, a 10% devaluation in the Canadian dollar to the United States dollar would result in our consolidated balance sheets being negatively impacted by a $24.2 million cumulative translation adjustment in accumulated other comprehensive loss.

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ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed 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 Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of March 31, 2017. Based on this evaluation, our Chief Executive Officer, and Chief Financial Officer concluded that as of March 31, 2017, our disclosure controls and procedures were not effective at the reasonable assurance level as a result of the material weaknesses previously disclosed under Item 9A. "Controls and Procedures" in our Annual Report on Form 10-K for our fiscal year ended December 31, 2016. During the year ended December 31, 2016, our internal control over financial reporting was not effective due to the aggregation of internal control deficiencies related to the implementation, design, maintenance and operating effectiveness of various transaction, process level, and monitoring controls. These deficiencies largely have arisen during fiscal 2016 because of growth of the Company, increases in employee headcount to support growth, and frequent changes in organizational structure that were not adequately supported by elements of our internal control over financial reporting. The deficiencies can be grouped generally as ineffective training programs, accounting policies and procedures, monitoring and management review controls, contract review, and procure-to-pay procedures.
However, after giving full consideration to these material weaknesses, and the additional analyses and other procedures that we performed to ensure that our consolidated financial statements included in this Quarterly Report on Form 10-Q were prepared in accordance with U.S. generally accepted accounting principles (GAAP), our management has concluded that our consolidated financial statements present fairly, in all material respects, our financial position, results of operations and cash flows for the periods disclosed in conformity with GAAP.
Remediation Plan and Efforts with Respect to Material Weaknesses
Our management has developed a plan to remediate the material weaknesses in our internal control over financial reporting and remediation efforts through March 31, 2017 including the following:
Providing SOX 404 and internal control training to accounting, executive management, and various department personnel;
documenting accounting, entity level, and IT policies and procedures that support our internal control infrastructure;
redesigning the contract review process that improves communication and informational flow between the various Company departments including legal and accounting for the complete and accurate recording of contract provisions; and
redesigning and implementing changes to certain processes and internal controls.
Change in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) of the Exchange Act that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are subject, from time to time, to routine legal proceedings and claims arising out of the normal course of business. There has been no material change in the nature of our legal proceedings from the description provided in our Annual Report on Form 10-K for the year ended December 31, 2016, except as described below:
Shareholder Class Action Lawsuit
The putative shareholder class action lawsuit filed in the United States District Court for the Northern District of California in November 2016 against us and certain of our executive officers alleging violations of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder was dismissed with prejudice against the particular claimants in March 2017.
Other Proceedings
During the third quarter of 2015, rights to appeal prior decisions granting the Renewable Energy Approval (REA) under Ontario's Environmental Protection Act for our K2 facility were exhausted without further appeal. As a result, a stay of a previously filed civil suit against the K2 facility pending final determination of the REA was lifted, allowing such suit to move forward if the claimants so choose to continue such suit. Such civil suit had claimed, among other things, nuisance based on both the construction and operation of the facility. Since the third quarter of 2016, various motions have been filed by each of K2 and the claimants in the civil suit, and a decision was issued in April 2017. Following a resolution of certain costs associated with the litigation, the claimants will have an opportunity to file an amended claim. We do not believe this proceeding will have a material adverse effect on our business, financial position or liquidity based on the information currently available to us, but can give no assurance, that it will ultimately be resolved favorably to K2.
ITEM 1A. RISK FACTORS
In addition to the other information set forth in this report, you should consider the risks described under the caption “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes in our risk factors as described in such document.


45


ITEM 6. EXHIBITS
Exhibit
No.
  
Description
 
 
 
3.1
  
Amended and Restated Certificate of Incorporation of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)).
 
 
3.2
  
Amended and Restated Bylaws of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
 
 
4.1
  
Form of Class A Stock Certificate (Incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).
 
 
4.2
  
Indenture, dated July 28, 2015, among Pattern Energy Group Inc., as issuer, Pattern US Finance Company LLC, as subsidiary guarantor, and Deutsche Bank Trust Company Americas, as trustee, related to 4.00% Convertible Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 28, 2015).
 
 
 
4.3
 
Indenture, dated as of January 25, 2017, among Pattern Energy Group Inc., Pattern US Finance Company LLC, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, related to 5.875% Senior Notes due 2024 (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated January 20, 2017).
 
 
 
31.1
  
Certifications of the Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
31.2
  
Certifications of the Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
32*
  
Certifications of the Company’s Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
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
*
This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed “filed” by the Company for purposes of Section 18 of the Exchange Act.

46


SIGNATURE
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.
 
 
 
 
Pattern Energy Group Inc.
 
 
 
 
Dated:
May 9, 2017
By:
/s/ Michael J. Lyon
 
 
 
Michael J. Lyon
 
 
 
Chief Financial Officer
 
 
 
 
 
 
 
(On behalf of the Registrant and as Principal Financial Officer)


47