Edgar Filing: Pattern Energy Group Inc.

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2013.

¨	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.)

Pier1, 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 x

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 x No ¨

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

As of October 31, 2013 there were 35,528,283 shares of Class A common stock outstanding, $0.01 par value, and 15,555,000 shares of Class B common stock outstanding, $0.01 par value.

PATTERN ENERGY GROUP INC.

INDEX TO

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013

PART I. FINANCIAL INFORMATION


Item 1.	Pattern Energy Group Inc. Financial Statements (Unaudited):

	Balance Sheets as of September 30, 2013 and December 31, 2012	4
	Statements of Operations for the three and nine months ended September 30, 2013	5
	Statement of Changes in Shareholder’s Deficit for the nine months ended September 30, 2013	6
	Statement of Cash Flows for the nine months ended September 30, 2013	7
	Notes to Financial Statements	8

	Pattern Energy Predecessor Financial Statements (Unaudited):

	Combined Balance Sheets as of September 30, 2013 and December 31, 2012	10
	Combined Statements of Operations for the three and nine months ended September 30, 2013 and 2012	11
	Combined Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2013 and 2012	12
	Combined Statement of Changes in Equity for the nine months ended September 30, 2013	13
	Combined Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	14
	Notes to Combined Financial Statements	15

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	35

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 6.	Exhibits	37
	Signature	38

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. 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:

•

accidents or other unscheduled shutdowns or disruptions affecting our machinery, or equipment, or those of our suppliers or customers;

•

the results of our hedging and other risk management activities;

•

our ability to comply with covenants contained in our debt instruments;

•

relationships with our partners and franchisees;

•

our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;

•

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

•

dependence on one principal supplier for merchandise;

•

maintenance of our credit ratings and ability to receive open credit lines from our suppliers;

•

the effects of competition;

•

continued creditworthiness of, and performance by, counterparties;

•

weather interference with business operations;

•

fluctuations in the debt markets;

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, “Item 1A. Risk Factors” and elsewhere in this report and (2) “Risk Factors” in our final prospectus filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) of the Securities Act of 1933, as amended on September 26, 2013.

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.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Pattern Energy Group Inc.

Balance Sheets

(In U.S. Dollars)


	September 30, 2013			December 31, 2012
	(unaudited)
Assets
Cash and cash equivalents	$	557		$	897

Total assets	$	557		$	897

Liabilities and shareholder’s (deficit) equity
Other accrued liabilities	$	6,700		$	6,700

Total liabilities		6,700			6,700
Shareholder’s (deficit) equity:
Common shares, $0.01 par value; 1,000 shares authorized; 100 shares issued and outstanding		1			1
Additional paid-in capital		2,999			999
Accumulated deficit		(9,143	)		(6,803	)

Total shareholder’s deficit		(6,143	)		(5,803	)

Total liabilities and shareholder’s (deficit) equity	$	557		$	897

See accompanying notes to financial statements.

Pattern Energy Group Inc.

Statements of Operations

(In U.S. Dollars)

(Unaudited)


	Three months ended September 30, 2013			Nine months ended September 30, 2013
Revenue	$	—		$	—
Cost of revenue		—			—
Operating expenses:
General and administrative		641			740

Total operating expenses		641			740
Net loss before income tax		(641	)		(740	)
Tax provision		—			1,600

Net loss	$	(641	)	$	(2,340	)

See accompanying notes to financial statements.

Pattern Energy Group Inc.

Statement of Changes in Shareholder’s Deficit

(In U.S. Dollars)

(Unaudited)


	Common Stock				Additional		Accumulated			Total Shareholder’s
	Shares		Amount		Paid-in Capital		Deficit			Deficit
Balance at December 31, 2012		100		1	$	999	$	(6,803	)	$	(5,803	)
Contribution		—		—		2,000		—			2,000
Net loss		—		—		—		(2,340	)		(2,340	)

Balance at September 30, 2013		100		1	$	2,999	$	(9,143	)	$	(6,143	)

See accompanying notes to financial statements.

Pattern Energy Group Inc.

Statement of Cash Flows

(In U.S. Dollars)

(Unaudited)


	Nine months ended September 30, 2013
Operating activities:
Net loss	$	(2,340	)

Net cash used in operating activities		(2,340	)
Investing activities		—
Financing activities
Contribution		2,000

Net cash provided by financing activities		2,000

Net decrease in cash and cash equivalents		(340	)
Cash and cash equivalents, beginning of period		897

Cash and cash equivalents, end of period	$	557

See accompanying notes to financial statements

Pattern Energy Group Inc.

Notes to Financial Statements

(Unaudited)

1.	Organization

Pattern Energy Group Inc., (“Pattern”) was organized in the state of Delaware on October 2, 2012. Under Pattern’s charter, Pattern is authorized to issue up to 1,000 shares of common stock. Pattern issued 100 shares on October 17, 2012, to Pattern Renewables LP, a 100% owned subsidiary of Pattern Energy Group LP (“PEG LP”). On September 24, 2013, Pattern’s charter was amended, and the number of shares that Pattern is authorized to issue was increased to 620,000,000 total shares; 500,000,000 of which are designated Class A Common Stock, 20,000,000 of which are designated Class B Common Stock, and 100,000,000 of which are designated Preferred Stock.

Pattern plans to operate as an independent power company focused on owning and operating power projects.

2.	Formation of Pattern and Initial Public Offering

Pattern was formed by PEG LP for the purpose of an initial public offering (“IPO”) and does not have any historical financial operating results. Therefore, the historical financial statements of Pattern’s predecessor, which consist of the combined financial statements of a combination of entities and assets owned by PEG LP and collectively referred to as Pattern Energy Predecessor, are presented separately below.

On October 2, 2013, Pattern closed the IPO and now trades on NASDAQ under the ticker symbol PEGI and on the Toronto Stock Exchange under the ticker symbol PEG. Concurrent with the IPO, Pattern entered into a series of transactions with PEG LP (“Contribution Transactions”), whereby PEG LP contributed certain entities and assets to Pattern, which entities and assets are the same as those of Pattern Energy Predecessor with the exception of the PEG LP retained Gulf Wind interest. Proceeds from the IPO were used (i) to provide the cash portion of consideration paid to PEG LP in connection with the contribution of assets to Pattern, (ii) for working capital and general corporate purposes and (iii) to repay the revolving credit facility. See Note 4, Subsequent Events, and separate financial statements of Pattern Energy Predecessor. Pattern’s fiscal year end is December 31.

3.	Summary of Significant Accounting Policies

Basis of Presentation

The accompanying financial statements have been prepared in accordance with U.S. generally accepted accounting principles.

Unaudited Interim Financial Information

The accompanying balance sheet as of September 30, 2013, and statements of operations for the three and nine months ended September 30, 2013, and the statements of changes in shareholder’s deficit and cash flows for the nine months ended September 30, 2013 are unaudited. The unaudited interim financial statements have been prepared on a basis consistent with the annual financial statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to present fairly Pattern’s financial position and results of operations for the three and nine months ended September 30, 2013 and statement of cash flow for the nine months ended September 30, 2013. The results of the three and nine months ended September 30, 2013 are not necessarily indicative of the results to be expected for the calendar year ending December 31, 2013, or for other interim periods or future years.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the U.S. 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.

Start-Up Costs

Start-up costs incurred are expensed.

Offering Costs

Offering costs incurred by PEG LP, Pattern’s parent, have been deferred and recorded by PEG LP as prepaid expense as incurred. Upon the successful completion of Pattern’s offering these costs were reimbursed by Pattern and recorded by Pattern as a reduction to shareholder’s equity.

Income taxes

Pattern accounts for income taxes under an asset and liability approach. Deferred income taxes reflect the impact of temporary differences between assets and liabilities recognized for financial reporting purposes and the amounts recognized for income tax reporting purposes, net operating loss carry forwards, and other tax credits measured by applying currently enacted tax laws. A valuation allowance is provided when necessary to reduce deferred tax assets to an amount that is more likely than not to be realized.

4.	Subsequent Events

On October 2, 2013, Pattern issued 16,000,000 shares of Class A common stock in an IPO generating net proceeds of approximately $318 million. Concurrent with the IPO, Pattern issued 19,445,000 shares of Class A common stock and 15,555,000 shares of Class B common stock to PEG LP and utilized approximately $233 million of the net proceeds of the IPO as a portion of the consideration to PEG LP for the Contribution Transactions and repaid the $56.0 million balance in the revolving credit facility. On October 8, 2013, Pattern’s underwriters exercised in full their overallotment option to purchase 2,400,000 shares of Class A common stock from PEG LP, the selling stockholder, pursuant to the overallotment option granted by PEG LP in connection with the IPO.

In connection with the Contribution Transactions, PEG LP retained a 40% portion of the interest in Gulf Wind previously held by Pattern’s predecessor such that, at the completion of the IPO, Pattern, PEG LP and our joint venture partner will hold interests of approximately 40%, 27% and 33%, respectively, of the distributable cash flow of Gulf Wind, together with certain allocated tax items.

In connection with the IPO and pursuant to the terms of the contribution agreement, PEG LP contributed to Pattern certain projects and related entities, consisting of interests in eight wind power projects located in the United States, Canada and Chile. Pattern also assumed the liabilities associated with the contributed assets, including project-level or holding company indebtedness, ordinary-course operational liabilities, and indemnities that PEG LP granted for the benefit of certain lenders. These indemnity obligations indemnify the lenders for the amount of any project-level investment tax credit cash grants that might be recaptured by the U.S. Treasury. Pattern also assumed indemnities that were granted by PEG LP to certain lenders in connection with certain legal costs, as well as to certain owner lessors of a project in connection with certain potential tax losses.

Effective with Pattern’s IPO, PEG LP’s project operations and maintenance personnel and certain of its executive officers became Pattern employees and their employment with PEG LP was terminated. PEG LP retained only those employees whose primary responsibilities relate to project development or legal, financial or other administrative functions. Pattern entered into a bilateral services agreement with PEG LP that provides for Pattern and PEG LP to benefit, primarily on a cost-reimbursement basis, from the respective management and other professional, technical and administrative personnel, all of whom report to and are managed by Pattern’s executive officers.

Pattern Energy Predecessor

Combined Balance Sheets

(In thousands of U.S. Dollars)


	September 30,			December 31,
	2013			2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	149,089		$	17,573
Trade receivables		20,189			13,715
Related party receivable		78			—
Reimbursable interconnection costs		1,444			51,307
Derivative assets, current		15,789			17,177
Prepaid expenses and other current assets		14,648			13,794

Total current assets		201,237			113,566
Restricted cash		40,560			13,904
Turbine advances		—			44,150
Deferred development costs		—			26,544
Construction in progress		—			6,081
Property, plant and equipment, net of accumulated depreciation of $159,991 and $100,247 in 2013 and 2012, respectively		1,506,029			1,668,302
Unconsolidated investments		78,271			36,218
Derivative assets		75,502			62,895
Deferred financing costs, net of accumulated amortization of $14,877 and $9,311 in 2013 and 2012, respectively		37,240			42,654
Net deferred tax assets		11,949			4,940
Other assets		13,659			16,475

Total assets	$	1,964,447		$	2,035,729

Liabilities and equity
Current liabilities:
Accounts payable and other accrued liabilities	$	11,790		$	7,743
Accrued construction costs		6,112			67,206
Related party payable		—			198
Accrued interest		1,385			559
Contingent liabilities		—			8,001
Derivative liabilities, current		16,296			13,462
Revolving credit facility		56,000			—
Current portion of long-term debt		47,004			137,258

Total current liabilities		138,587			234,427
Long-term debt		1,217,972			1,153,312
Derivative liabilities		10,535			35,326
Asset retirement obligation		20,631			19,056
Net deferred tax liabilities		3,712			3,662
Other long-term liabilities		3,333			528

Total liabilities		1,394,770			1,446,311
Equity:
Capital		473,514			545,471
Accumulated income		33,050			2,910
Accumulated other comprehensive loss		(13,631	)		(34,264	)

Total equity before noncontrolling interest		492,933			514,117
Noncontrolling interest		76,744			75,301

Total equity		569,677			589,418

Total liabilities and equity	$	1,964,447		$	2,035,729

See accompanying notes to combined financial statements.

Pattern Energy Predecessor

Combined Statements of Operations

(In thousands of U.S. Dollars)

(Unaudited)


	Three Months ended September 30,						Nine Months ended September 30,
	2013			2012			2013			2012
Revenue:
Electricity sales	$	37,950		$	22,285		$	130,533		$	72,160
Energy derivative settlements		2,656			3,308			12,873			14,967
Unrealized gain (loss) on energy derivative		6,659			(8,690	)		(5,222	)		(6,944	)
Related party revenue		202			—			465			—
Other revenue		9,790			—			21,157			—

Total revenue		57,257			16,903			159,806			80,183
Cost of revenue:
Project expense		14,592			9,301			42,061			25,061
Depreciation and accretion		21,194			12,815			61,758			34,551

Total cost of revenue		35,786			22,116			103,819			59,612
Gross profit (loss)		21,471			(5,213	)		55,987			20,571
Operating expenses:
General and administrative		213			74			562			587
Related party general and administrative		3,607			2,836			8,968			7,587

Total operating expenses		3,820			2,910			9,530			8,174
Operating income (loss)		17,651			(8,123	)		46,457			12,397
Other income (expense):
Interest expense		(14,695	)		(9,013	)		(48,169	)		(25,195	)
Equity in earnings in unconsolidated investments		1,845			117			5,188			13
Interest rate derivative settlements		(1,059	)		—			(1,059	)		—
Unrealized gain (loss) on derivatives		776			63			10,909			(32	)
Net gain on transactions		—			—			7,200			4,173
Other income, net		321			286			2,123			970

Total other expense		(12,812	)		(8,547	)		(23,808	)		(20,071	)
Net income (loss) before income tax		4,839			(16,670	)		22,649			(7,674	)
Tax provision (benefit)		595			243			(6,801	)		1,247

Net income (loss)		4,244			(16,913	)		29,450			(8,921	)
Net income (loss) attributable to noncontrolling interest		3,248			(7,494	)		(690	)		(5,943	)

Net income (loss) attributable to controlling interest	$	996		$	(9,419	)	$	30,140		$	(2,978	)

Unaudited pro forma net income after tax:
Net income before income tax							$	22,649
Pro forma tax benefit								(2,232	)

Pro forma net income							$	24,881

See accompanying notes to combined financial statements.

Pattern Energy Predecessor

Combined Statements of Comprehensive Income (Loss)

(In thousands of U.S. Dollars)

(Unaudited)


	Three Months ended September 30,						Nine Months ended September 30,
	2013			2012			2013			2012
Net income (loss)	$	4,244		$	(16,913	)	$	29,450		$	(8,921	)
Other comprehensive loss:
Foreign currency translation, net of tax		2,377			4,383			(4,950	)		3,566
Effective portion of change in fair market value of derivatives, net of tax		1,899			(2,437	)		27,486			(10,215	)
Proportionate share of equity investee’s other comprehensive income ( loss), net of tax		55			(180	)		1,656			(1,950	)

Total other comprehensive income (loss), net of tax		4,331			1,766			24,192			(8,599	)

Comprehensive income (loss)		8,575			(15,147	)		53,642			(17,520	)
Less comprehensive income attributable to noncontrolling interest:
Net income (loss) attributable to noncontrolling interest	$	3,248		$	(7,494	)	$	(690	)	$	(5,943	)
Effective portion of change in fair market value of derivatives, net of tax		(17	)		(171	)		3,559			(1,453	)

Comprehensive income (loss) attributable to noncontrolling interest		3,231			(7,665	)		2,869			(7,396	)

Comprehensive income (loss) attributable to controlling interest	$	5,344		$	(7,482	)	$	50,773		$	(10,124	)

See accompanying notes to combined financial statements.

Pattern Energy Predecessor

Combined Statement of Changes in Equity

(In thousands of U.S. Dollars)

(Unaudited)


	Controlling Interest											Noncontrolling Interest
	Capital			Accumulated Income		Accumulated Other Comprehensive Income (Loss)			Total			Capital			Accumulated Income (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total			Total Equity
Balances at December 31, 2012	$	545,471		$	2,910	$	(34,264	)	$	514,117		$	74,177		$	12,366		$	(11,242	)	$	75,301		$	589,418
Contribution		32,677			—		—			32,677			—			—			—			—			32,677
Distribution		(104,634	)		—		—			(104,634	)		(1,426	)		—			—			(1,426	)		(106,060	)
Net income (loss)		—			30,140		—			30,140			—			(690	)		—			(690	)		29,450
Other comprehensive income, net of tax		—			—		20,633			20,633			—			—			3,559			3,559			24,192

Balances at September 30, 2013	$	473,514		$	33,050	$	(13,631	)	$	492,933		$	72,751		$	11,676		$	(7,683	)	$	76,744		$	569,677

See accompanying notes to combined financial statements.

Pattern Energy Predecessor

Combined Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)


	Nine Months ended September 30,
	2013			2012
Operating activities
Net income (loss)	$	29,450		$	(8,921	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and accretion		61,758			34,551
Amortization of financing costs		5,428			1,268
Unrealized (gain) loss on derivatives		(5,687	)		6,976
Net gain on transactions		(7,200	)		(4,173	)
Deferred taxes		(6,801	)		1,247
Equity in earnings in unconsolidated investments		(5,188	)		(13	)
Changes in operating assets and liabilities:
Trade receivables		(7,935	)		2,716
Prepaid expenses and other current assets		(3,393	)		(3,378	)
Other assets (non current)		(358	)		(314	)
Accounts payable and other accrued liabilities		4,862			(931	)
Related party receivable/payable		(291	)		682
Accrued interest payable		857			985
Contingent liabilities		—			(188	)
Long-term liabilities		2,896			—

Net cash provided by operating activities		68,398			30,507
Investing activities
Receipt of ITC Cash Grant		173,446			—
Proceeds from sale of investments and tax credits		14,254			4,173
Decrease in restricted cash - interconnect and PPA security		63,732			441
Increase in restricted cash - interconnect and PPA security		(80,567	)		(844	)
Capital expenditures		(120,965	)		(360,076	)
Deferred development costs		(528	)		(5,402	)
Distribution from unconsolidated investments		10,463			—
Contribution to unconsolidated investments		(8,737	)		(20,954	)
Reimbursable interconnection receivable		49,715			(41,392	)
Other assets (non current)		1,740			1,835

Net cash provided by (used in) investing activities		102,553			(422,219	)
Financing activities
Capital contributions - controlling interest		32,677			234,787
Capital distributions - controlling interest		(98,886	)		(25,779	)
Capital distributions - noncontrolling interest		(1,426	)		(1,054	)
Decrease in restricted cash - debt service reserves		116,654			8,773
Increase in restricted cash - debt service reserves		(126,475	)		(15,209	)
Payment for deferred financing costs		(294	)		(45	)
Proceeds from revolving credit facility		56,000			—
Proceeds from long-term debt		138,620			194,858
Repayment of long-term debt		(41,283	)		(21,190	)
Repayment of construction and grant loans		(114,056	)		—

Net cash (used in) provided by financing activities		(38,469	)		375,141
Effect of exchange rate changes on cash and cash equivalents		(966	)		748
Net change in cash and cash equivalents		132,482			(16,571	)
Cash and cash equivalents at beginning of period		17,573			47,672

Cash and cash equivalents at end of period	$	149,089		$	31,849

Supplemental disclosure
Cash payments for interest and commitment fees	$	45,178		$	29,351
Schedule of non-cash activities
Change in fair value of interest rate swaps		38,266			(10,216	)
Change in fair value of contingent liabilities		8,001			(314	)
Amortization of deferred financing costs - included as construction in progress		175			2,429
Capitalized interest		3,230			6,362
Capitalized commitment fee		39			556
Change in property, plant and equipment		(160,021	)		41,372
Transfer of capitalized assets to South Kent joint venture		49,275			—
Non-cash distribution to parent		(5,748	)		—

See accompanying notes to combined financial statements.

Pattern Energy Predecessor

Notes to Combined Financial Statements

(Unaudited)

1. Description of Business

Pattern Energy Predecessor (the “Company”) is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts in certain markets, currently including the United States, Canada and Chile. The Company consists of the combined operations of certain entities and assets owned by Pattern Energy Group LP (“PEG LP”), as discussed in the basis of presentation below. The principal business objective of the Company is to produce stable and sustainable cash flows through the generation and sale of energy.

On October 2, 2013, Pattern Energy Group Inc. (“Pattern”) completed an initial public offering of stock (‘IPO”). Concurrent with the IPO, Pattern entered into a series of transactions with PEG LP (“Contribution Transactions”), whereby PEG LP contributed certain entities and assets to Pattern, which entities and assets are the same as those of Pattern Energy Predecessor with the exception of the PEG LP retained Gulf Wind interest. See Note 16, Subsequent Events.

Basis of Presentation

The Company is not an existing legal entity. Rather, it is a combination of entities and assets currently owned by Pattern Energy Group LP. The Company owns 100% of Hatchet Ridge Wind LLC (Hatchet Ridge), St. Joseph Windfarm Inc. (St. Joseph), Spring Valley Wind LLC (Spring Valley), Pattern Santa Isabel LLC (Santa Isabel) and Ocotillo Express LLC (Ocotillo). The Company owns a controlling interest in Pattern Gulf Wind Holdings LLC (Gulf Wind) and noncontrolling interests in South Kent Wind LP (South Kent) and AEI-Pattern Holdings Limitada (El Arrayán). The Company combines Gulf Wind and the wholly-owned investments as consolidating investments, and uses the equity method to combine its noncontrolling investments. As of September 30, 2013, the Company’s project portfolio consists of interests in eight wind power projects, including six projects in operation (Gulf Wind, Hatchet Ridge, St. Joseph, Spring Valley, Santa Isabel and Ocotillo), and two projects under construction (El Arrayán and South Kent).

The Company receives certain project, administrative and overhead services from PEG LP which are recorded as expenses in the combined statements of operations or are capitalized as deferred development costs in the balance sheets, and as increased capital contributions. See Note 15, Related Party Transactions. The accompanying historical financial statements include the combined results of operations of the Company as if it had operated as a single company during the periods presented.

Unaudited Interim Financial Information

The interim combined balance sheet as of September 30, 2013, and the combined statements of operations and comprehensive income (loss) for the three and nine months ended September 30, 2013 and 2012 and the statement of changes in equity and cash flows for the nine months ended September 30, 2013 and 2012 are unaudited. The unaudited interim financial statements have been prepared on a basis consistent with the annual combined financial statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to present fairly the Company’s financial position and results of operations for the three and nine months ended September 30, 2013 and 2012, and cash flows for the nine months ended September 30, 2013 and 2012. The results of the three and nine months ended September 30, 2013 are not necessarily indicative of the results to be expected for the calendar year ending December 31, 2013, or for other interim periods or future years.

These interim unaudited combined financial statements should be read in conjunction with the audited financial statements and related notes included in the Company’s prospectus filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) of the Securities Act of 1933, as amended on September 26, 2013.

2. Summary of Significant Accounting Policies

Principles of Consolidation

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

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 those estimates, and such differences may be material to the combined financial statements.

Unaudited Pro Forma Income Tax

In order to present the tax effect of the Contribution Transactions, the Company has presented a pro forma income tax provision as if the Contribution Transactions occurred effective January 1, 2012 and as if the Company were under control of a Subchapter C-Corporation for U.S. federal income tax purposes.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents, trade receivables, notes receivable and derivative assets. The Company places its cash and cash equivalents with high quality institutions.

For the three months ended September 30, 2013 and 2012, Customer A accounted for 10.8% and 45.6% of total revenue, respectively, Customer B accounted for 12.3% and 32.5% of total revenue, respectively, and Customer C accounted for 10.5% and 33.9% of total revenue, respectively. For the nine months ended September 30, 2013 and 2012, Customer A accounted for 15.7% and 34.5% of total revenue, respectively, Customer B accounted for 13.5% and 26.4% of total revenue, respectively, and Customer C accounted for 12.7% and 20.7% of total revenue, respectively.

The Company’s derivative assets are placed with counterparties that are creditworthy institutions. A derivative asset was generated from Credit Suisse Energy LLC, the counterparty to a 10-year fixed-for-floating swap related to annual electricity generation at the Company’s Gulf Wind project. The Company’s reimbursements for prepaid interconnect network upgrades are with large utility companies. The Company has determined that the credit rating of Credit Suisse and the large utility companies are of a high quality as of September 30, 2013 and December 31, 2012.

3. Prepaid expenses and other current assets

The following table presents the components of prepaid expenses and other current assets (in thousands):


	September 30, 2013		December 31, 2012
Prepaid expenses	$	10,559	$	7,202
Sales tax		71		3,275
Interconnection network upgrade receivable		2,517		1,854
Other current assets		1,501		1,463

Prepaid expenses and other current assets	$	14,648	$	13,794

4. Property, Plant and Equipment

The following presents the categories within property, plant and equipment (in thousands):


	September 30, 2013			December 31, 2012
Operating wind farms	$	1,662,273		$	1,765,200
Furniture, fixtures and equipment		3,731			3,333
Land		16			16

Subtotal		1,666,020			1,768,549
Less: accumulated depreciation		(159,991	)		(100,247	)

	$	1,506,029		$	1,668,302

The Company recorded depreciation expense related to property, plant and equipment of $20.9 million and $12.6 million for the three months ended September 30, 2013 and 2012, respectively, and $60.9 million and $34.0 million for the nine months ended September 30, 2013 and 2012, respectively.

In June 2013, the Company received $115.9 million and $57.6 million for Ocotillo and Santa Isabel, respectively, under a cash grant in lieu of investment tax credit (Cash Grant) from the U.S. Department of the Treasury. In December 2012, the Company received $79.9 million for Spring Valley under a Cash Grant from the U.S. Department of the Treasury. The Company recorded the cash proceeds as a deduction from the carrying amount of the related wind farm assets which resulted in the assets being recorded at lower amounts and a reduction of depreciation expense per year of approximately $4.0 million, $5.8 million, and $2.9 million, for Spring Valley, Ocotillo and Santa Isabel, respectively.

For the three and nine months ended September 30, 2013, the Cash Grants received for Ocotillo and Santa Isabel in June 2013, and for Spring Valley in December 2012 reduced depreciation expense recorded in the combined statements of operations by approximately $3.2 million and $9.8 million, respectively. For the three and nine months ended September 30, 2012, the Cash Grants did not reduce depreciation expense recorded in the combined statements of operations.

5. Unconsolidated Investments

The following presents projects that are accounted for under the equity method of accounting (in thousands):


					Percentage of Ownership
	September 30, 2013		December 31, 2012		September 30, 2013			December 31, 2012
South Kent	$	57,786	$	17,895		50.0	%		50.0	%
El Arrayan		20,485		18,323		31.5	%		31.5	%

	$	78,271	$	36,218

South Kent

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year Purchase Price Agreement (PPA). Construction commenced in March 2013.

El Arrayán

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Chile. The project has a 20-year PPA and commenced construction in May 2012.

6. Accounts payable and other accrued liabilities

The following table presents the components of accounts payable and other accrued liabilities (in thousands):


	September 30, 2013		December 31, 2012
Accounts payable	$	179	$	331
Other accrued liabilities		4,802		3,840
Property tax payable		2,618		3,444
Sales tax payable		4,191		128

Accounts payable and other accrued liabilities	$	11,790	$	7,743

7. Long term debt

The Company’s long term debt as of September 30, 2013 and December 31, 2012 is presented below (in thousands):


							Interest Rate as of
	September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012			Interest Type and Maturity
Santa Isabel bridge loan	$	—		$	38,337			n/a			2.31	%	Variable	July 2013 or earlier
Ocotillo bridge loan		—			56,586			n/a			3.31	%	Variable	August 2013
Hatchet Ridge term loan		244,153			251,119			1.43	%		1.43	%	Imputed	December 2032
Gulf Wind term loan		166,760			174,969			3.28	%		3.36	%	Variable	March 2020
St. Joseph term loan		224,003			238,737			5.88	%		5.88	%	Fixed	May 2031
Spring Valley term loan		175,136			178,900			2.66	%		2.62	%	Variable	June 2030
Santa Isabel term loan		116,181			119,035			4.57	%		4.57	%	Fixed	September 2033
Ocotillo commercial term loan		230,943			160,299			2.93	%		3.31	%	Variable	August 2020
Ocotillo development term loan		107,800			72,588			2.28	%		2.41	%	Variable	August 2033

		1,264,976			1,290,570
Less: Current Portion		(47,004	)		(137,258	)

	$	1,217,972		$	1,153,312

Interest and commitment fees incurred, and interest expense recorded in the Company’s combined statements of operations is as follows (in thousands):


	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Interest and commitment fees incurred	$	14,858		$	10,431		$	43,584		$	30,442
Capitalized interest and commitment fees		(2,372	)		(2,157	)		(3,269	)		(6,918	)
Letter of credit fees		852			135			2,426			403
Amortization of financing costs		1,357			604			5,428			1,268

Interest expense	$	14,695		$	9,013		$	48,169		$	25,195

Ocotillo

In July 2013, Ocotillo commenced commercial operations on the remaining 42 MW of its electricity generating capacity. In August 2013, Ocotillo received $58.6 million as partial reimbursement of interconnect upgrade costs and repaid its network upgrade bridge loan of $56.6 million. In September 2013, Ocotillo converted its two construction loans to term loans and prepaid $2.2 million of the development bank loan and $5.3 million of the commercial bank loan pursuant to a proposal initiated by Ocotillo and accepted by the lenders.

Revolving Credit Facility

As of September 30, 2013 and December 31, 2012, letters of credit of $44.3 million and $39.1 million, respectively, have been issued and loans of $56.0 million and zero, respectively, have been drawn against the revolving credit facility.

As of September 30, 2013, the Eurodollar interest rate on the $56.0 million loan was 3.70%.

8. Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated cost, at all of its projects, of decommissioning the turbines, removing above-ground installations and restoring the sites at a date that is 19.3 to 20 years from the commencement of commercial operations.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of September 30, 2013 and December 31, 2012 (in thousands):


	September 30, 2013			December 31, 2012
Beginning asset retirement obligation	$	19,056		$	10,342
Additions during the year		767			7,971
Foreign currency translation adjustment		(94	)		59
Accretion expense		902			684

Ending asset retirement obligation	$	20,631		$	19,056

9. Derivative Instruments

The Company employs a variety of derivative instruments to manage its exposure to fluctuations in interest rates and electricity prices. The following tables present the amounts that are recorded in the Company’s combined balance sheets as of September 30, 2013 and December 31, 2012 (in thousands):

Undesignated Derivative Instruments Classified as Assets (Liabilities):


					As of						For the period ended
					Fair Market Value						QTD Gain (loss) Recognized into Income			YTD Gain (loss) Recognized into Income
Derivative Type	Quantity		Maturity Dates		Current Portion			Long-Term Portion			QTD Gain (loss) Recognized into Income			YTD Gain (loss) Recognized into Income
September 30, 2013
Interest rate swaps		6		6/30/2030	$	(3,931	)	$	9,805		$	731		$	10,782
Interest rate cap		1		12/31/2024		—			574			45			127
Energy derivative		1		4/30/2019		15,789			58,614			6,659			(5,222	)

					$	11,858		$	68,993		$	7,435		$	5,687

December 31, 2012 (audited)
Interest rate swaps		6		6/30/2030	$	(1,980	)	$	(2,931	)		NA		$	(4,908	)
Interest rate cap		1		12/31/2024		—			447			NA			(44	)
Energy derivative		1		4/30/2019		17,177			62,448			NA			(6,952	)

					$	15,197		$	59,964		$	—		$	(11,904	)

September 30, 2012
Interest rate cap		1		12/31/2024	$	—		$	459		$	63		$	(32	)
Energy derivative		1		4/30/2019		16,224			63,408			(8,690	)		(6,944	)

					$	16,224		$	63,867		$	(8,627	)	$	(6,976	)


Designated Derivative Instruments Classified as Assets ( Liabilities):
					As of						For the period ended
					Fair Market Value						QTD Gain (loss) Recognized in OCI			YTD Gain (loss) Recognized in OCI
Derivative Type	Quantity		Maturity Dates		Current Portion			Long-Term Portion			QTD Gain (loss) Recognized in OCI			YTD Gain (loss) Recognized in OCI
September 30, 2013
Interest rate swaps		6		6/30/2033	$	(2,106	)	$	6,509		$	810		$	7,317
Interest rate swaps		7		3/15/2020		(5,356	)		(9,501	)		123			7,269
Interest rate swaps		2		6/28/2030		(4,903	)		(1,034	)		966			12,900

					$	(12,365	)	$	(4,026	)	$	1,899		$	27,486

December 31, 2012 (audited)
Interest rate swaps		6		6/30/2033	$	(952	)	$	(1,962	)		NA		$	(2,914	)
Interest rate swaps		7		3/15/2020		(5,558	)		(16,568	)		NA			(1,835	)
Interest rate swaps		2		6/28/2030		(4,972	)		(13,865	)		NA			(6,421	)

					$	(11,482	)	$	(32,395	)	$	—		$	(11,170	)

September 30, 2012
Interest rate swaps		7		3/15/2020	$	(5,347	)	$	(18,100	)	$	(842	)	$	(3,155	)
Interest rate swaps		2		6/28/2030		(3,533	)		(15,943	)		(1,595	)		(7,059	)

					$	(8,880	)	$	(34,043	)	$	(2,437	)	$	(10,214	)

10. Accumulated Other Comprehensive Income (Loss)


	Foreign Currency			Effective Portion of Change in Fair Value of Derivatives			Proportionate Share of Equity Investee’s OCI			Total
Balances at January 1, 2012	$	(2,903	)	$	(32,707	)	$	—		$	(35,610	)
Net current period other comprehensive income (loss)		2,749			(11,170	)		(1,475	)		(9,896	)

Balances at December 31, 2012 (audited)		(154	)		(43,877	)		(1,475	)		(45,506	)
Net current period other comprehensive (loss) income		(4,950	)		27,486			1,656			24,192

Balances at September 30, 2013	$	(5,104	)	$	(16,391	)	$	181		$	(21,314	)

11. 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 combined 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 as follows:

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.

Short-term financial instruments consist principally of cash, cash equivalents, accounts receivable, notes receivable, accounts payable and other accrued liabilities. Based on the nature and short maturity of these instruments their fair value is approximated using carrying cost and they are presented in the Company’s financial statements at carrying cost. The fair values of cash, cash equivalents and restricted cash are a Level 1 hierarchy. The fair values of accounts receivable, notes receivable, accounts payable and other accrued liabilities are Level 2 hierarchy.

Long term debt is presented on the combined balance sheet at amortized cost. 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 (Level 2). 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 (Level 3).

Derivatives and contingent liabilities subject to re-measurement are presented in the financial statements at fair value. The interest rate swaps, interest rate cap and swaptions were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the counterparties’ credit default hedge rate (Level 2). The fair value of contingent liabilities is based upon the time of realization and the probability of the contingent event (Level 3). The energy derivative instrument was valued by discounting the projected net cash flows over the remaining life of the derivative using forward energy curves adjusted by a nonperformance risk factor (Level 3).

The following tables present the fair values according to each defined level (in thousands):


Financial assets and (liabilities) measured on a recurring basis:

	Fair Value Measurements Using
	Level 1			Level 2			Level 3
September 30, 2013
Interest rate swaps	$	—		$	(10,517	)	$	—
Interest rate cap		—			574			—
Energy derivative		—			—			74,403

	$	—		$	(9,943	)	$	74,403

December 31, 2012 (audited)
Interest rate swaps	$	—		$	(48,787	)	$	—
Interest rate cap		—			447			—
Energy derivative		—			—			79,625
Contingent liabilities		—			—			(8,001	)

	$	—		$	(48,340	)	$	71,624

September 30, 2012
Interest rate swaps	$	—		$	(42,923	)	$	—
Interest rate cap		—			459			—
Energy derivative		—			—			79,632
Contingent liabilities		—			—			(6,300	)

	$	—		$	(42,464	)	$	73,332


Reconciliation of energy derivative and contingent liabilities measured at fair value using unobservable inputs (level 3):

	Contingent liabilities			Energy Derivative			Total
Balance at January 1, 2012	$	(5,986	)	$	86,577		$	80,591
Settlements		—			(19,644	)		(19,644	)
Change in fair value, net of settlements		(2,015	)		12,692			10,677

Balance at December 31, 2012 (audited)		(8,001	)		79,625			71,624
Settlements		8,001			(12,873	)		(4,872	)
Change in fair value, net of settlements		—			7,651			7,651

Balance at September 30, 2013	$	—		$	74,403		$	74,403

12. Income Taxes

The Company is treated as a pass-through entity for U.S. federal and state income tax purposes, except for certain of the Company’s Canadian and Chilean entities which are subject to Canadian and Chilean income taxes, a U.S. entity which is subject to Puerto Rico income taxes, and a U.S. entity which became subject to federal and state income taxes in 2012 after changing its tax status by electing to be treated as a Subchapter C corporation for federal income tax purposes, which required the inclusion of deferred tax assets related to book tax basis difference. The Company has recorded tax provisions or benefits for the Canadian and Chilean entities and U.S. entity. Deferred income taxes have been provided for net operating losses and temporary differences between book and tax basis. These differences create taxable or tax deductible amounts for future periods. The Company recorded income tax provision of $0.6 million and tax benefit of $6.8 million for the three and nine months ended September 30, 2013, respectively. The tax provision was comprised of estimated federal and provincial income taxes for the Company’s Canadian corporations and a U.S. entity.

The deferred tax assets and deferred tax liabilities resulted primarily from temporary differences between book and tax bases of assets and liabilities. The Company regularly assesses the likelihood that future taxable income levels will be sufficient to ultimately realize the tax benefits of the deferred tax assets. Should the Company determine that future realization of the tax benefits is not likely, additional valuation allowance would be established which would increase the Company’s tax provision in the period of such determination.

The threshold for recognizing the effects of tax return positions in the financial statements is more-likely-than-not that the position would be sustained by the taxing authority. The Company is required to measure a tax position meeting the more-likely-than-not criterion, based on the largest effect that is more than 50% likely to be realized. Management has analyzed the Company’s inventory of tax positions taken with respect to all applicable income tax issues for all open tax years (in each respective jurisdiction) and has concluded that no uncertain tax positions are required to be recognized in the Company’s combined financial statements. The Company is subject to examination by federal and state or provincial taxing authorities in Canada and the U.S. for the years 2009 through 2012.

13. Geographic Information

The table below provides information, by country, about the Company’s combined operations. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located (in thousands):


	Revenue								Property, Plant and Equipment, net
	Three months ended September 30,				Nine months ended September 30,				September 30,		December 31,
	2013		2012		2013		2012		2013		2012
United States	$	50,054	$	8,200	$	131,042	$	48,988	$	1,227,912	$	1,367,149
Canada		7,203		8,703		28,764		31,195		278,117		301,153

Total	$	57,257	$	16,903	$	159,806	$	80,183	$	1,506,029	$	1,668,302

14. Commitments, Contingencies and Warranties

Power Purchase Agreements

The Company has various PPAs that terminate from 2025 to 2039. The terms of the PPAs 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 respective PPAs. As of September 30, 2013, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $57.2 million to ensure its performance for the duration of the PPAs.

Project Finance Agreements

The Company has various project finance agreements which obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. The Company issued irrevocable letters of credit totaling $91.3 million, of which $44.3 million was from the Company’s revolving credit facility, to ensure performance under these various project finance agreements.

Contingent Liabilities

The Company has recorded contingent purchase price payment obligations related to acquired assets that were recorded at fair value and re-measured at each reporting date. The amount of recorded contingent purchase price obligations was zero and $8.0 million as of September 30, 2013 and December 31, 2012, respectively.

In addition, the Company has unrecorded purchase price payment obligations related to asset acquisitions that are contingent on future events. The amount of unrecorded contingent purchase price obligations was zero and $2.8 million as of September 30, 2013 and December 31, 2012, respectively.

Purchase Commitments

The Company has entered into various commitments with service providers related to the Company’s projects and operations of its business. Outstanding commitments with these vendors, excluding turbine operations and maintenance commitments, were $4.1 million and $5.1 million as of September 30, 2013 and December 31, 2012, respectively. The Company has open commitments for turbines of zero and $1.7 million, as of September 30, 2013 and December 31, 2012, respectively, and for construction of zero and $22.3 million as purchases of September 30, 2013 and December 31, 2012, respectively.

Turbine Availability Warranties

In May 2013, a blade separated from the turbine hub on one of the wind turbines at the Ocotillo project following which the Company shut down all of the SWT-2.3-108 turbines at the Ocotillo and Santa Isabel projects, pending determination of the cause. The turbine manufacturer has completed, and the Company has accepted, a root cause analysis, a remediation plan, including inspection, repair or replacement, and a return to service program for all of the SWT-2.3-108 blades. The Company’s warranties require the manufacturer to complete the remediation plan at its cost and pay liquidated damages to the projects in the event that turbine availability falls below specified thresholds.

In June 2013, the Company entered into warranty settlements with the blade manufacturer. The warranty settlements provide for total liquidated damage payments of approximately $19.4 million and $4.7 million for Ocotillo and Santa Isabel, respectively, as of September 30, 2013 and allows for a partial credit against future availability liquidated damages owed by the blade manufacturer. During the three and nine months ended September 30, 2013, the Company received payments of $6.8 million and $24.1 million, respectively, in connection with warranty settlements with the Company’s blade manufacturer. The Company estimates the maximum future refund of the liquidated damage payment to be $1.5 million and $1.4 million for Ocotillo and Santa Isabel, respectively, and has recorded a long term liability for these amounts as of September 30, 2013. The warranty settlements, net of the maximum estimated future refund to the blade manufacturer, have been recorded as other revenue in the combined statements of operations.

15. Related Party Transactions

The Company’s project management and administrative activities were provided by PEG LP. Costs associated with these activities are allocated to the Company and recorded in its combined statements of operations. Allocated costs include cash and non-cash compensation, other direct, general and administrative costs, and non-operating costs deemed allocable to the Company.

Measurement of allocated costs is based principally on time devoted to the Company by officers and employees of PEG LP. The Company believes the allocated costs presented in its combined statements of operations are a reasonable estimate of actual costs incurred to operate the business. The allocated costs are not the result of arms-length, free-market dealings.

The table below present allocated costs included in the combined statements of operations (in thousands):


	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Allocation of costs to:
Project expense	$	768		$	662		$	1,993		$	1,763
General and administrative		3,607			2,836			8,968			7,587
Other income		(17	)		(24	)		(551	)		(59	)

Total allocated costs	$	4,358		$	3,474		$	10,409		$	9,291

Letters of credit, indemnities and guarantees

PEG LP agreed to guarantee $14.0 million of El Arrayán’s payment obligations to a lender that has provided a $20 million credit facility for financing of El Arrayán’s recoverable, construction-period value added tax payments. The remaining $6.0 million of the credit facility has been guaranteed by another investor in El Arrayán.

Purchase Arrangements

The Company has purchase arrangements with PEG LP under which the latter purchases various services and supplies on behalf of the Company and receives reimbursement for these purchases. As of September 30, 2013 and December 31, 2012, the amounts payable to PEG LP for these purchases were approximately zero and $0.2 million, respectively.

Puerto Rico Electric Power Authority (PREPA)

The Company’s Santa Isabel project was in a dispute with PREPA over the appropriate rate being charged to the project for the electric services it uses. During the quarter ended September 30, 2013, the difference between what the Company believes is the appropriate monthly charge and PREPA’s bill was settled. PEG LP has agreed to provide the Company with an indemnity to mitigate the economic impact on the Company of this dispute. With the settlement of the dispute, PEG LP is expected to be released from the indemnity.

Management fees

The Company provides management services and receives a fee for such services under an agreement with South Kent, its joint venture investee. Management fees of $0.2 million and $0.5 million were recorded as related party revenue in the combined statements of operations for the three and nine months ended September 30, 2013, respectively, and related party receivable of $0.1 million was recorded in the combined balance sheet as of September 30, 2013. The Company eliminates the intercompany profit from management fees related to its ownership interest in South Kent.

16. Subsequent Events

Effective with Pattern’s IPO, PEG LP’s project operations and maintenance personnel and certain of its executive officers became Pattern’s employees and their employment with PEG LP was terminated. PEG LP retained only those employees whose primary responsibilities relate to project development or legal, financial or other administrative functions. Pattern entered into a bilateral services agreement with PEG LP that provides for Pattern and PEG LP to benefit, primarily on a cost-reimbursement basis, from the respective management and other professional, technical and administrative personnel, all of whom report to and are managed by Pattern’s executive officers.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of financial condition and results of operations relate to Pattern Energy Predecessor. As you read this discussion and analysis, refer to Pattern Energy Predecessor’s combined statements of operations and cash flows in this Form 10Q, which present the results of operations for the three and nine months ended September 30, 2013 and 2012, respectively, and cash flows for the nine months ended September 30, 2013 and 2012. Unless the context otherwise requires, references to “we,” “our,” “us,” or like terms, when used in a historical context (periods prior to October 2, 2013) refer to Pattern Energy Predecessor.

In connection with the Contribution Transactions, PEG LP retained a 40% portion of the interest in Gulf Wind previously held by Pattern Energy Predecessor such that, at the completion of the IPO, Pattern, PEG LP and our joint venture partner will hold interests of approximately 40%, 27% and 33%, respectively, of the distributable cash flow of Gulf Wind, together with certain allocated tax items.

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 own interests in eight wind power projects located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 1,041 MW, consisting of six operating projects and two projects under construction that will commence commercial operations prior to the end of the second quarter of 2014. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. Over 90% of the electricity to be generated by our projects will be sold under these power sale agreements which have a weighted average remaining contract life of approximately 19 years.

We intend to maximize long-term value for our shareholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around the core values of creating a safe, high-integrity and exciting work environment; applying rigorous analysis to all aspects of our business; and proactively working with our stakeholders in addressing environmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our shareholders, are to produce stable and sustainable cash available for distribution, selectively grow our project portfolio and our dividend 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 PEG LP and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per share over time. We expect our continuing relationship with PEG LP, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business.

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 revenue, cost of revenue, net income and cash provided by (used in) operating activities, we also consider MWh sold, average realized electricity price and Adjusted EBITDA in evaluating our operating performance and cash available for distribution as supplemental liquidity measures. Each of these key metrics is discussed below.

MWh Sold and Average Realized Electricity Price

The number of MWh sold and the average realized price per MWh sold are the operating metrics that determine our revenue. For any period presented, average realized electricity price represents total revenue from electricity sales and energy derivative settlements divided by the aggregate number of MWh sold.

Adjusted EBITDA

We define Adjusted EBITDA as net income before net interest expense, income taxes and depreciation and accretion, including our proportionate share of net interest expense, income taxes and depreciation and accretion of joint venture investments that are accounted for under the equity method, and excluding the effect of certain other items that we do not consider to be indicative of our ongoing operating performance such as mark-to-market adjustments and excluding the effect of certain other items that the Company does not consider to be indicative of its ongoing operating performance such as mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt and realized derivative gain or loss from refinancing transactions, and gain or loss related to acquisitions or divestitures. 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 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. Adjusted EBITDA is a non-U.S. GAAP measure.

The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented and is unaudited (in thousands):


	Pattern Energy Predecessor
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012			Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(U.S. dollars in thousands)
Net income (loss)	$	4,244		$	(16,913	)	$	29,450		$	(8,921	)
Plus:
Interest expense, net of interest income		14,260			8,817			45,932			24,513
Tax provision (benefit)		595			243			(6,801	)		1,247
Depreciation and accretion		21,194			12,815			61,758			34,551

EBITDA	$	40,293		$	4,962		$	130,339		$	51,390

Unrealized (gain) loss on energy derivative		(6,659	)		8,690			5,222			6,944
Unrealized (gain) loss on interest rate derivatives		(776	)		(63	)		(10,909	)		32
Realized loss on interest rate derivatives		1,059			—			1,059			—
Gain on transactions		—			—			(7,200	)		(4,173	)
Plus, our proportionate share in the following from our equity accounted investments:
Interest expense, net of interest income		91			—			39			—
Tax (benefit) provision		(36	)		1			(84	)		57
Depreciation and accretion		3			—			14			—
Unrealized gain on interest rate and currency derivatives		(2,143	)		(212	)		(6,091	)		(194	)
Realized loss (gain) on interest rate and currency derivatives		118			34			(35	)		38

Adjusted EBITDA	$	31,950		$	13,412		$	112,354		$	54,094

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 (used in) 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, which currently reflects the cash distributions to our joint venture partners in our Gulf Wind project in accordance with the provisions of its governing partnership agreement and may in the future reflect distribution to other joint venture partners, (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, and (vi) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.

The following table presents cash available for distribution for the periods presented and is unaudited (in thousands):


	Pattern Energy Predecessor
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012			Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(U.S. dollars in thousands)
Net cash provided by operating activities	$	26,739		$	5,696		$	68,398		$	30,507
Changes in current operating assets and liabilities		(8,753	)		(709	)		3,004			(74	)
Network upgrade reimbursement		618			618			1,236			5,027
Use of operating cash to fund maintenance and debt reserves		—			—			—			(525	)
Operations and maintenance capital expenditures		(56	)		(350	)		(431	)		(604	)
Less:
Distributions to noncontrolling interests		(258	)		—			(1,426	)		(1,054	)
Principal payments paid from operating cash flows ⁽¹⁾		(11,973	)		(4,018	)		(33,788	)		(21,190	)

Cash available for distribution	$	6,317		$	1,237		$	36,993		$	12,087

⁽¹⁾	Excludes $7,495 of principal pre-payments on our Ocotillo project which were paid from ITC cash grant proceeds

Results of Operations

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

The following table provides selected financial information for the periods presented and is unaudited (in thousands, except percentages):


	Three Months ended September 30,
	2013			2012			$ Change			% Change
Revenue	$	57,257		$	16,903		$	40,354			239	%

Project expense		14,592			9,301			5,291			57	%
Depreciation and accretion		21,194			12,815			8,379			65	%

Total cost of revenue		35,786			22,116			13,670			62	%
Gross profit (loss)		21,471			(5,213	)		26,684			512	%
Total operating expenses		3,820			2,910			910			31	%

Operating income (loss)		17,651			(8,123	)		25,774			317	%
Total other expenses		(12,812	)		(8,547	)		(4,265	)		50	%

Net income (loss) before income tax		4,839			(16,670	)		21,509			129	%
Tax provision		595			243			352			145	%

Net income (loss)		4,244			(16,913	)		21,157			125	%
Net income (loss) attributable to noncontrolling interest		3,248			(7,494	)		10,742			143	%

Net income (loss) attributable to controlling interest	$	996		$	(9,419	)	$	10,415			111	%

MWh sold and average realized electricity price. We sold 464,756MWh of electricity in the three months ended September 30, 2013 as compared to 352,897MWh sold in the three months ended September 30, 2012. This increase in MWh sold during 2013 as compared to 2012 was primarily attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively. Santa Isabel and Ocotillo production continued to be impacted by the turbine outage in the third quarter of 2013 though both projects returned to full service in the third quarter. Our average realized electricity price was approximately $87 per MWh in the three months ended September 30, 2013 as compared to approximately $73 per MWh in the three months ended September 30, 2012. The average realized electricity price in 2013 is higher than 2012 as the pricing terms under the Spring Valley, Santa Isabel and Ocotillo project PPAs are each higher than our previous overall average realized price.

Revenue. Revenue for the three months ended September 30, 2013 was $57.3 million compared to $16.9 million for the three months ended September 30, 2012, an increase of $40.4 million, or approximately 239%. This increase in revenue during 2013 as

compared to 2012 was attributed to an increase of $15.7 million in electricity sales primarily attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively. In addition, during the three months ended September 30, 2013 we recorded other revenue of $9.8 million related to warranty settlement payments we received from a turbine supplier during the period as a result of the turbines at Ocotillo and Santa Isabel projects being off line for a portion of the period. During the three months ended September 30, 2013, we recorded a $6.7 million unrealized gain on energy derivative compared to an $ 8.7 million unrealized loss in 2012. The value of our energy derivative, and the amount of unrealized gain or loss we record, increases and decreases due to our monthly derivative settlements and changes in forward electricity prices, which are derived from and impacted by changes in forward natural gas prices.

Cost of revenue. Cost of revenue for the three months ended September 30, 2013 was $35.8 million compared to $22.1 million for the three months ended September 30, 2012, an increase of $13.7 million, or approximately 62%. The increase in cost of revenue during 2013 as compared to 2012 was attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively, with depreciation and accretion contributing $8.4 million of the $13.7 million increase in 2013 as compared to 2012. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Related party general and administrative expense. Related party general and administrative expense for the three months ended September 30, 2013 was $3.6 million compared to $2.8 million for the three months ended September 30, 2012, an increase of $0.8 million, or approximately 29%, resulting primarily from the increased staffing and overhead costs related to commercial operations commencing at Spring Valley, Santa Isabel and Ocotillo as well as our ownership in El Arrayán and South Kent as construction on these projects advanced in 2013.

Other expense. Other expense for the three months ended September 30, 2013 was $12.8 million compared to $8.5 million for the three months ended September 30, 2012. The increase of $4.3 million in other expense during 2013 as compared to 2012 was primarily attributable to a $5.7 million increase in interest expense in 2013 attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively, as well as increased costs related to our revolving credit facility. In 2013, we also had a $1.7 million increase in equity in earnings in unconsolidated investments, which was primarily attributable to interest rate swaps that were entered into in 2013 and which are not designated as hedges. The gain on these interest rate swaps was attributable to an increase in the forward interest rate curve during the three months ended September 30, 2013. In 2013, we also had a $1.1 million increase in interest rate derivative settlements as a portion of our interest rate swaps on the Ocotillo project are not designated as hedges and therefore our settlements on these derivatives will be recorded as realized gains or losses in other expense. The interest rate derivative settlements in 2013 were partially offset by an increase in the unrealized gain on derivatives as compared to 2012 as there was an increase in the forward interest rate curve which decreases our liability under these Ocotillo interest rate swaps and increases our unrealized gain on derivatives.

Tax provision. The tax provision was a $0.6 million expense for the three months ended September 30, 2013 compared to $0.2 million for the three months ended September 30, 2012. This increase was primarily the result of the Santa Isabel project holding company being subject to U.S. income taxes for this period in 2013.

Noncontrolling interest. The net gain attributable to noncontrolling interest was $3.2 million for the three months ended September 30, 2013 compared to a $7.5 million loss attributable to noncontrolling interest for the three months ended September 30, 2012. The noncontrolling interest income or loss calculation is based on the hypothetical liquidation at book value method of accounting for the earnings attributable to the noncontrolling interest’s ownership in Gulf Wind and the higher income allocation for the three months ended September 30, 2013 is primarily attributable to the period over period increase in Gulf Wind’s unrealized gain on energy derivative. Note, the forgoing discussion does not reflect the adjustment to noncontrolling interest due to the retention by PEG LP of an approximate 27% interest in Gulf Wind in connection with the Contribution Transactions which occurred on October 2, 2013.

Adjusted EBITDA. Adjusted EBITDA for the three months ended September 30, 2013 was $32.0 million compared to $13.4 million for the three months ended September 30, 2012, an increase of $18.6 million. The increase in Adjusted EBITDA during 2013 as compared to 2012 was primarily attributable to the commencement of operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

The following table provides selected financial information for the periods presented and is unaudited (in thousands, except percentages):


	Nine Months ended September 30,
	2013			2012			$ Change			% Change
Revenue	$	159,806		$	80,183		$	79,623			99	%

Project expense		42,061			25,061			17,000			68	%
Depreciation and accretion		61,758			34,551			27,207			79	%

Total cost of revenue		103,819			59,612			44,207			74	%
Gross profit		55,987			20,571			35,416			172	%
Total operating expenses		9,530			8,174			1,356			17	%

Operating income		46,457			12,397			34,060			275	%
Total other expenses		(23,808	)		(20,071	)		(3,737	)		19	%

Net income (loss) before income tax		22,649			(7,674	)		30,323			395	%
Tax (benefit) provision		(6,801	)		1,247			(8,048	)		-645	%

Net income (loss)		29,450			(8,921	)		38,371			430	%
Net (loss) income attributable to noncontrolling interest		(690	)		(5,943	)		5,253			88	%

Net income (loss) attributable to controlling interest	$	30,140		$	(2,978	)	$	33,118			1112	%

MWh sold and average realized electricity price. We sold 1,726,632MWh of electricity in the nine months ended September 30, 2013 as compared to 1,220,117MWh sold in the nine months ended September 30, 2012. This increase in MWh sold during 2013 as compared to 2012 was primarily attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively. Santa Isabel and Ocotillo production was negatively impacted by the turbine outage during 2013 although all turbines had been returned to service by September 30, 2013. During the nine months ended September 30, 2013, higher production at our Gulf Wind Project resulting from higher winds offset lower production at our St. Joseph project which had lower winds in 2013 as compared to 2012. Our average realized electricity price was approximately $83 per MWh in the nine months ended September 30, 2013 as compared to approximately $71 per MWh in the nine months ended September 30, 2012. The average realized electricity price in 2013 is higher than 2012 as the pricing terms under the Spring Valley, Santa Isabel and Ocotillo project PPAs are each higher than our previous overall average realized price.

Revenue. Revenue for the nine months ended September 30, 2013 was $159.8 million compared to $80.2 million for the nine months ended September 30, 2012, an increase of $79.6 million, or approximately 99%. This increase in revenue during 2013 as compared to 2012 was attributed to an increase in electricity sales attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively, and higher production at Gulf Wind during 2013 as compared to 2012 primarily due to higher winds, offset by lower production at our St. Joseph project primarily due to lower winds in 2013 as compared to 2012 and lower energy derivative settlements period over period due to higher spot power prices at Gulf wind during 2013 as compared to 2012. In addition, during the nine months ended September 30, 2013 we recorded other revenue of $21.2 million related to warranty settlement payments we received from a turbine supplier during the period as a result of the turbines at Ocotillo and Santa Isabel projects being off line for a portion of the period.

Cost of revenue. Cost of revenue for the nine months ended September 30, 2013 was $103.8 million compared to $59.6 million for the nine months ended September 30, 2012, an increase of $44.2 million, or approximately 74%. The increase in cost of revenue during 2013 as compared to 2012 was attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively, with depreciation and accretion contributing $27.2 million of the $44.2 million increase in 2013 as compared to 2012 with the remaining increase attributable to increased project expenses as new projects commenced operations. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease and other costs associated with managing, operating and maintaining the facility, including adding site employees and operations center staff.

Related party general and administrative expense. Related party general and administrative expense for the nine months ended September 30, 2013 was $9.0 million compared to $7.6 million for the nine months ended September 30, 2012, an increase of $1.4 million, or approximately 18%, resulting primarily from the increased staffing and overhead costs related to commercial operations commencing at Spring Valley, Santa Isabel and Ocotillo as well as our ownership in El Arrayán and South Kent as construction on these projects advanced in 2013.

Other expense. Other expense for the nine months ended September 30, 2013 was $23.8 million compared to $20.1 million for the nine months ended September 30, 2012. The increase of $3.7 million in other expense during 2013 as compared to 2012 was attributable to a $23.0 million increase in interest expense in 2013 attributable to the commencement of commercial operations at Spring Valley in August 2012, at Santa Isabel in December 2012, and for 223 megawatts and 42 megawatts at Ocotillo in December 2012 and July 2013, respectively. Offsetting this increase in interest expense, we had a $5.2 million increase in equity in earnings in unconsolidated investments, which was primarily attributable to interest rate swaps that were entered into in 2013 and which are not designated as hedges. The gain on these interest rate swaps was attributable to an increase in the forward interest rate curve after these interest rate swaps were entered into. In addition, we had a $10.9 million increase in unrealized gain on derivatives as a portion of our interest rate swaps on the Ocotillo project are not designated as hedges and there was an increase in the forward interest rate curve which decreases our liability under these interest rate swaps and increase our unrealized gain on derivatives during the nine months ended September 30, 2013. Offsetting the unrealized gain on derivatives is a $1.1 million loss on interest rate derivatives during the nine months ended September 30, 2013.

Tax provision. The tax provision was a $6.8 million benefit for the nine months ended September 30, 2013 compared to $1.2 million expense for the nine months ended September 30, 2012. This was principally the result of the Santa Isabel project holding company being subject to U.S. income taxes for this period in 2013, and the impact of its receipt of a U.S. Department of the Treasury cash grant resulting in recognition of a deferred tax asset and a tax provision benefit.

Noncontrolling interest. The net loss attributable to noncontrolling interest was $0.7 million for the nine months ended September 30, 2013 compared to $5.9 million loss for the nine months ended September 30, 2012. The noncontrolling interest income or loss calculation is based on the hypothetical liquidation at book value method of accounting for the earnings attributable to the noncontrolling interest’s ownership in Gulf Wind. The amount of loss allocated decreased for the nine months ended September 30, 2013 due to an increase in the value of Gulf Wind’s interest rate swaps. Note, the forgoing discussion does not reflect the adjustment to noncontrolling interest due to the retention by PEG LP of an approximate 27% interest in Gulf Wind in connection with the Contribution Transactions which occurred on October 2, 2013.

Adjusted EBITDA. Adjusted EBITDA for the nine months ended September 30, 2013 was $112.4 million compared to $54.1 million for the nine months ended September 30, 2012, an increase of $58.3 million. The increase in Adjusted EBITDA during 2013 as compared to 2012 was primarily attributable to the commencement of operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012.

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 shareholders, (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. Our sources of liquidity include cash generated by our operations, ITC cash grants, 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 restricted and unrestricted cash balances and availability under our credit agreements. As of September 30, 2013, our available liquidity was $302.9 million, including restricted cash on hand of $40.6 million, unrestricted cash on hand of $149.1 million, and $113.2 million available under our credit agreements.

We believe that following the completion of our IPO, we will have sufficient liquid assets, cash flows from operations, ITC cash grants 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. Additionally, we believe that our construction projects have been sufficiently capitalized such that we will not need to seek additional financing arrangements in order to complete construction and achieve commercial operations at these projects. 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, we may, from time to time, issue debt or equity securities.

Cash available for distribution was $6.3 million for the three months ended September 30, 2013 as compared to $1.2 million for the three months ended September 30, 2012. This increase in cash available for distribution was primarily the result of increased cash provided by operations, net of changes in current operating assets and liabilities, in 2013 as compared to 2012 which was attributable to the commencement of commercial operations at Spring Valley in August 2012, and at Santa Isabel and Ocotillo in December 2012. The increased cash provided by operations was partially offset by higher principal payments quarter over quarter which was attributable to the commencement of commercial operations at Spring Valley in August 2012, and at Santa Isabel and Ocotillo in December 2012.

Cash available for distribution was $37.0 million for the nine months ended September 30, 2013 as compared to $12.1 million for the nine months ended September 30, 2012. This increase in cash available for distribution was primarily the result of an increase in cash provided by operations, net of changes in current operating assets and liabilities, in 2013 as compared to 2012 which was attributable to the commencement of commercial operations at Spring Valley in August 2012, and at Santa Isabel and Ocotillo in December 2012. The increase in net cash provided by operations in 2013 as compared to 2012 more than offset the increase in principal payments period over period which was also attributable to the commencement of commercial operations at Spring Valley in August 2012, and at Santa Isabel and Ocotillo in December 2012.

We intend to pay regular quarterly dividends in U.S. dollars to holders of our Class A shares. Our quarterly dividend will initially be set at $0.3125 per Class A share, or $1.25 per Class A share on an annualized basis, and the amount may be changed in the future without advance notice. We have established our initial quarterly dividend level based on a targeted cash available for distribution payout ratio of 80% both prior to and following the Conversion Event, 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 Class A share over time. However, the determination of the amount of cash dividends to be paid to holders of our Class A shares 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.

Cash Flows

We use traditional measures of cash flows, 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 to evaluate our periodic cash flow results.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Net cash provided by operating activities was $68.4 million for the nine months ended September 30, 2013 as compared to $30.5 million for the nine months ended September 30, 2012. Electricity sales were $58.4 million higher during 2013 as compared to 2012 which was attributable to the commencement of commercial operations at Spring Valley in August 2012 and at Santa Isabel and Ocotillo in December 2012 and higher production at Gulf Wind during 2013 as compared to 2012. In addition, during the nine months ended September 30, 2013 we recorded other revenue of $21.2 million related to warranty settlement payments we received from a turbine supplier during the period as a result of the turbines at Ocotillo and Santa Isabel projects being off line for a portion of the period. These increases in electricity sales and other revenue were offset by a $10.6 million increase in the quarter-over-quarter reduction of cash flow provided by operations related to an increase in accounts receivable consistent with our terms under the power sales agreements, a quarter-over-quarter increase of $17.0 million in project expenses, and a quarter-over-quarter increase in cash interest expense and settlement on interest rate derivatives of $20.0 million.

Net cash provided by investing activities was $102.6 million for the nine months ended September 30, 2013, which consisted of $173.4 million of ITC grant proceeds at Ocotillo and Santa Isabel, $49.7 million of net reimbursement of interconnection network upgrades primarily at our Ocotillo project, and $14.3 million of proceeds from the sale of investments and tax credits, offset by $121.0 million of capital expenditures primarily at Ocotillo. Net cash used in investing activities was $422.2 million for the nine months ended September 30, 2012, which consisted primarily of $360.1 million of capital expenditures at Spring Valley, Santa Isabel and Ocotillo, $41.4 million for interconnection network upgrades primarily at our Ocotillo project and $21.0 million of equity investments in our project.

Net cash used in financing activities for the nine months ended September 30, 2013 was $38.5 million, which was primarily attributable to $100.3 million of capital distributions, $155.3 million of loan repayments, including $7.5 million of loan prepayments at Ocotillo using a portion of the ITC grant proceeds, offset by $32.7 million of capital contributions, $138.6 million of loan borrowings primarily at Ocotillo and Santa Isabel, and a $56.0 million loan draw under our revolving credit facility. Net cash provided by financing activities for the nine months ended September 30, 2012 was $375.1 million, which was primarily attributable $234.8 million of capital contributions, $194.9 million of loan proceeds related to the construction of Spring Valley and Santa Isabel offset by capital distributions and loan repayments.

Capital Expenditures and Investments

We will initially own only those projects that we acquired through the Contribution Transactions. Each of the acquired project entities have secured all of the required project equity needed to complete the construction and achieve commercial operations at our construction projects and funding for all remaining planned construction costs, including contingency allowances, is available under financing commitments from project lenders. All capital expenditures and investments in 2013 have either been funded by PEG LP or are available from project finance lenders under project-level credit facilities. For the fourth quarter of 2013, we expect capital expenditures to be de minimis.

Following the completion of our IPO, we expect to make investments in additional projects. Although we have no commitments to make any such acquisitions, we consider it reasonably likely that we may have the opportunity to acquire the PEG LP near-term projects under our purchase rights within the 24 month period following the completion of our IPO. 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.

Critical Accounting Policies and Estimates

In applying the critical accounting policies set forth below, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. These estimates are based on management’s experience, the terms of existing contracts, management’s observance of trends in the wind power industry, information provided by our power purchasers and information available to management from other outside sources, as appropriate. These estimates are subject to an inherent degree of uncertainty.

We use estimates, assumptions and judgments for certain items, including the depreciable lives of property, plant and equipment, derivatives, income tax, revenue recognition, certain components of cost of revenue and exemptions and reduced reporting requirements provided by the JOBS Act. These estimates, assumptions and judgments are derived and continually evaluated based on available information, experience and various assumptions we believe to be reasonable under the circumstances. To the extent these estimates are materially incorrect and need to be revised, our operating results may be materially adversely affected.

Property, Plant and Equipment

Property, plant and equipment represents the costs of completed and operational projects transferred from construction in progress as well as land, computer equipment and software, furniture and fixtures, leasehold improvements and other equipment. Property, plant and equipment are stated at cost, less accumulated depreciation. Depreciation is calculated using the straight-line method over the assets’ useful lives. Wind power projects are depreciated over 20 years and the remaining assets are depreciated over three to five years. Land is not depreciated. Improvements to property, plant and equipment deemed to extend the useful economic life of an asset are capitalized. Repair and maintenance costs are expensed as incurred.

Derivatives

We have, and we intend to, enter into derivative transactions for the purpose of reducing exposure to fluctuations in interest rates and electricity prices. Our predecessor has entered into fixed for floating interest rate swap agreements and has designated these derivatives as qualified cash flow hedges of its expected interest payments on variable rate debt. Our predecessor has also entered into interest rate swaptions and interest rate caps.

We recognize our derivative instruments at fair value in the combined balance sheet. Accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether the derivative instrument has been designated as part of a hedging relationship and on the type of hedging relationship.

For derivative instruments that are designated as cash flow hedges the effective portion of change in fair value of the derivative is reported as a component of other comprehensive income. The ineffective portion of change in fair value is recorded as a component of net income on the combined statements of operations.

For undesignated derivative instruments their change in fair value is reported as a component of net income on the combined statements of operations.

Interest rate swaptions are instruments used to fix the terms of prospective interest rate derivatives that may be required when the related debt is refinanced. An interest rate cap is an instrument used to reduce exposure to future variable interest rates when the related debt is expected to be refinanced.

We entered into interest rate swaptions in 2009. The swaptions were terminated in 2010. Our predecessor entered into an interest rate cap in 2010. The cap remains in place as of September 30, 2013.

We entered into an electricity price arrangement, which qualifies as a derivative, that fixes the price of approximately 58% of the electricity generation expected to be produced and sold by Gulf Wind through April 2019, and which reduces our exposure to spot electricity prices.

Our swaptions, interest rate cap and energy derivative agreement do not qualify for hedge accounting.

Income Tax

Income taxes have not been provided for because our predecessor was treated as a pass-through entity for U.S. federal and state income tax purposes, except for several specific circumstances involving its Canadian entities, which are subject to Canadian income taxes, its Chilean entities, which are subject to Chilean income taxes, a U.S. entity that is subject to Puerto Rican taxes and a U.S.

entity which became subject to U.S. income taxes in 2012. U.S. federal and state income taxes are assessed at the owner level and

each owner is liable for its own tax payments. Certain combined entities are corporations or have elected to be taxed as corporations.

In these circumstances, income tax is accounted for under the asset and liability method.

Revenue Recognition

We sell the electricity we generate under the terms of our power sale agreements or at spot market prices. Revenue is recognized based upon the amount of electricity delivered at rates specified under the contracts, assuming all other revenue recognition criteria are met. We evaluate our PPAs to determine whether they are in substance leases or derivatives and, if applicable, recognize revenue pursuant to Accounting Standards Codification 840, or “ASC 840,” Leases and Accounting Standards Codification 815, or “ASC815,” Derivatives and Hedging, respectively. As of September 30, 2013, there were no PPAs that are accounted for as leases or derivatives.

We also generate renewable energy credits as we produce electricity. Certain of these energy credits are sold independently in an open market and revenue is recognized at the time title to the energy credits is transferred to the buyer.

We acquired a ten-year energy derivative instrument under the terms of its acquisition of Gulf Wind, which fixes approximately 58% of our expected electricity sales at Gulf Wind through April 2019. The energy derivative instrument reduces exposure to changes in commodity prices by allowing us to lock in a fixed price per MWh for a specified amount of annual electricity production. The monthly settlement amounts under the energy hedge are accounted for as energy derivative settlements in the combined statements of operations. The change in the fair value of the energy hedge is classified as energy derivative revenue in the combined statements of operations.

Cost of Revenue

Our cost of revenue is comprised of direct costs of operating and maintaining our power projects, including labor, turbine service arrangements, land lease royalties, depreciation, amortization, property taxes and insurance.

JOBS Act

In April 2012, the JOBS Act was enacted. Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the U.S. Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are electing to delay such adoption of new or revised accounting standards, and as a result, we may not comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for other companies.

Subject to certain conditions set forth in the JOBS Act and Canadian securities laws, as an emerging growth company, we intend to rely on certain of these exemptions, including, without limitation, providing an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404 and complying with any requirement that may be adopted regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements (auditor discussion and analysis). These exemptions will apply for a period of five years following the completion of this offering; although, if the market value of our shares that are held by non-affiliates exceeds $700 million as of any June 30 before that time, we would cease to be an emerging growth company as of the following December 31.

Contractual Obligations

We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs, as disclosed in the Prospectus. See also Note 7, Long-term Debt, and Note 14, Commitments, Contingencies and Warranties, in the combined financial statements for additional discussion of contractual obligations.

Off-Balance Sheet Arrangements

As of September 30, 2013, we had no off-balance sheet arrangements and have not entered into any transactions involving uncombined, limited purpose entities or commodity contracts.

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 through the use of long-term power sale agreements with creditworthy counterparties. Our predecessor’s financial results reflect approximately 323,000MWh of electricity sales in the year ended December 31, 2012 that were not subject to power sale agreements and were subject to spot market pricing. A hypothetical increase or decrease of $3.00 per MWh (or an approximately 12% change) in these spot market prices would have increased or decreased earnings by $1.0 million, respectively, for the year ended December 31, 2012.

Interest Rate Risk

We use a variety of derivative instruments to manage our exposure to fluctuations in interest rates, including interest rate swaps and interest rate caps, primarily in the context of our project-level indebtedness. We generally match the tenor and amount of these instruments to the tenor and amount, respectively, of the related debt financing. We also will have exposure to changes in interest rates with respect to our revolving credit agreement to the extent that we make draws under that facility. A hypothetical increase or decrease in short-term interest rates by 1% would not have changed our earnings for the year ended December 31, 2012.

Foreign Currency Risk

We manage our foreign currency risk through the consideration of forward exchange rate derivatives. Certain of our power sale agreements are U.S. dollar denominated and others are Canadian dollar denominated. Our predecessor did not enter into forward exchange rate derivatives to manage our exposure to Canadian dollar denominated revenues at our St. Joseph contract in the past. Our predecessor’s financial results include approximately $41.4 million of revenue that was earned pursuant to Canadian dollar denominated power sale agreements. A hypothetical increase of US$0.10 per Canadian dollar would have increased our earnings by $0.2 million for the year ended December 31, 2012, and a hypothetical decrease of US$0.10 per Canadian dollar would have decreased our earnings by $0.2 million for the year ended December 31, 2012.

ITEM 4.

CONTROLS AND PROCEDURES

The Company maintains disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision and with the participation of the Company’s management, including its principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2013.

There has been no change in the Company’s internal control over financial reporting during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

The Company is 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 the Company’s legal proceedings from the description provided in the Prospectus.

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 Prospectus. There have been no material changes in the Company’s risk factors as described in the Prospectus.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On October 2, 2013, the Company completed its initial public offering of 16,000,000 shares of Class A common stock at a price of $22.00 per share for an aggregate offering price of approximately $352 million. On October 8, 2013, the underwriters exercised an overallotment option to acquire an additional 2,400,000 of shares from Pattern Energy Group LP, the selling shareholder, at a price of $22.00 per share for an aggregate price of approximately $52.8 million. The offer and sale of the shares of Class A common stock were registered under the Securities Act pursuant to a Registration Statement on Form S-1 (File No. 333-190538), which was declared effective by the SEC on September 26, 2013. The initial public offering commenced on September 27, 2013, and terminated after the sale of all of the shares offered. Of the 35,528,283 shares of Class A common stock 83,183 were issued to the Company’s management and 19,445,000 of the Company’s Class A shares and 15,555,000 of the Company’s Class B shares were issued to the selling shareholder.

BMO Nesbitt Burns Inc., RBC Dominion Securities Inc., Morgan Stanley & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, CIBC World Markets Inc., Scotia Capital Inc., Wells Fargo Securities, LLC, Canaccord Genuity Corp. and Raymond James Ltd. acted as the underwriters of the offering. BMO Nesbitt Burns Inc., RBC Dominion Securities Inc. and Morgan Stanley & Co. LLC acted as the representatives of the several underwriters of the offering.

The Company received aggregate net proceeds from the initial public offering of approximately $318 million, after deducting underwriting discounts and commissions, and IPO costs of $34.0 million. None of the underwriting discounts and commissions or other offering expenses were incurred by or paid to directors or officers of the Company or their associates or persons owning 10 percent or more of the Company’s common stock or to any of the Company’s affiliates.

The Company used the net proceeds from the offering (i) to provide $233 million (i.e., the cash portion) of the consideration to be paid to Pattern Energy Group LP to acquire the projects to be contributed by Pattern Energy Group LP to the Company (the Contribution Transactions), (ii) to repay $56.0 million outstanding under the Company’ revolving credit facility, 2013, and (iii) for working capital and general corporate purposes. In connection with the Contribution Transactions referred to in (i) above, the Company also issued to the selling shareholder 19,445,000 Class A shares and 15,555,000 Class B shares as consideration for the assets that were contributed to the Company.

There has been no material change in the Company’s use of the net proceeds from the offering as described in the Prospectus.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS


Exhibit No.		Description

4.1		Amended and Restated Certificate of Incorporation of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1/A dated September 20, 2013 (Registration No. 333-190538)).

4.2		Amended and Restated Bylaws of Pattern Energy Group Inc. (Incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).

4.3		Pattern Energy Group Inc. 2013 Equity Incentive Award Plan (Incorporated by reference to Exhibit 10.2 to the Registrant’s Registration Statement on Form S-1/A dated September 3, 2013 (Registration No. 333-190538)).

31.1		Certification of the Company’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Company’s Chief Financial Officer 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 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.

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act and are deemed not filed for purposes of Section 18 of the Exchange Act and otherwise are not subject to liability under these sections.

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.


Dated: November 4, 2013		Pattern Energy Group Inc.

	By	/s/ Michael M. Garland
		Michael M. Garland
		President and Chief Executive Officer

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company