Edgar Filing: ATLANTIC POWER CORP

at_Current_Folio_10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10‑Q


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2016
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

COMMISSION FILE NUMBER 001‑34691

ATLANTIC POWER CORPORATION

(Exact name of registrant as specified in its charter)


British Columbia, Canada (State or other jurisdiction of incorporation or organization)	55‑0886410 (I.R.S. Employer Identification No.)
3 Allied Drive, Suite 220 Dedham, MA (Address of principal executive offices)	02026 (Zip code)

(617) 977‑2400

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, 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. (Check one):


Large accelerated filer ☐	Accelerated filer ☒	Non‑accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ☐

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

The number of shares outstanding of the registrant’s Common Stock as of August 4, 2016 was 120,508,716.

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ATLANTIC POWER CORPORATION

FORM 10‑Q

THREE AND SIX MONTHS ENDED JUNE 30, 2016

Index

	General:		3
		PART I—FINANCIAL INFORMATION
ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
		Consolidated Balance Sheets as of June 30, 2016 (unaudited) and December 31, 2015	4
		Consolidated Statements of Operations for the three and six months ended June 30, 2016 and June 30, 2015 (unaudited)	5
		Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2016 and June 30, 2015 (unaudited)	6
		Consolidated Statements of Cash Flows for the six months ended June 30, 2016 and June 30, 2015 (unaudited)	7
		Notes to Consolidated Financial Statements (unaudited)	8
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	38
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 4.		CONTROLS AND PROCEDURES	59
		PART II—OTHER INFORMATION	61
ITEM 1.		LEGAL PROCEEDINGS	61
ITEM 1A.		RISK FACTORS	61
ITEM 6.		EXHIBITS	62

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GENERAL

In this Quarterly Report on Form 10‑Q, references to “Cdn$” and “Canadian dollars” are to the lawful currency of Canada and references to “$” and “US$” and “U.S. dollars” are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.

Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10‑Q to “we,” “us,” “our,” “Atlantic Power” and the “Company” refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.

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ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions of U.S. dollars)


	June 30,		December 31,
	2016		2015
		(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	154.2	$	72.4
Restricted cash		14.3		15.2
Accounts receivable		42.9		39.6
Current portion of derivative instruments asset (Notes 7 and 8)		1.6		—
Inventory		17.3		16.9
Prepayments		8.6		8.3
Other current assets		2.5		4.5
Total current assets		241.4		156.9
Property, plant, and equipment, net of accumulated depreciation of $268.8 million and $236.3 at June 30, 2016 and December 31, 2015, respectively		768.1		777.7
Equity investments in unconsolidated affiliates (Note 4)		281.0		286.2
Power purchase agreements and intangible assets, net of accumulated amortization of $271.0 million and $238.0 million at June 30, 2016 and December 31, 2015, respectively		287.0		308.9
Goodwill		134.5		134.5
Derivative instruments asset (Notes 7 and 8)		1.1		0.3
Deferred income taxes		2.2		—
Other assets		6.0		6.7
Total assets	$	1,721.3	$	1,671.2
Liabilities
Current liabilities:
Accounts payable	$	6.4	$	6.9
Accrued interest		0.9		1.6
Other accrued liabilities		22.5		25.4
Current portion of long-term debt (Note 5)		96.4		15.8
Current portion of derivative instruments liability (Notes 7 and 8)		23.6		36.7
Other current liabilities		4.4		2.5
Total current liabilities		154.2		88.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 5)		807.8		682.7
Convertible debentures, net of unamortized deferred financing costs (Note 6)		163.4		277.7
Derivative instruments liability (Notes 7 and 8)		28.5		20.8
Deferred income taxes		69.1		85.7
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $15.4 million and $14.0 million at June 30, 2016 and December 31, 2015, respectively		27.0		27.0
Other long-term liabilities		54.4		53.2
Total liabilities		1,304.4		1,236.0
Equity
Common shares, no par value, unlimited authorized shares; 120,682,964 and 122,153,082 issued and outstanding at June 30, 2016 and December 31, 2015		1,286.8		1,290.6
Accumulated other comprehensive loss (Note 2)		(120.2)		(139.3)
Retained deficit (Note 12)		(971.0)		(937.4)
Total Atlantic Power Corporation shareholders’ equity		195.6		213.9
Preferred shares issued by a subsidiary company (Note 12)		221.3		221.3
Total equity		416.9		435.2
Total liabilities and equity	$	1,721.3	$	1,671.2

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions of U.S. dollars, except per share amounts)

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Project revenue:
Energy sales	$	45.1	$	47.5	$	97.6	$	101.5
Energy capacity revenue		37.3		38.0		69.2		71.5
Other		15.8		17.6		37.8		41.4
		98.2		103.1		204.6		214.4
Project expenses:
Fuel		35.1		38.0		74.0		84.2
Operations and maintenance		30.0		35.3		51.2		56.8
Development		—		—		—		1.1
Depreciation and amortization		25.5		28.2		50.3		56.1
		90.6		101.5		175.5		198.2
Project other income:
Change in fair value of derivative instruments (Notes 7 and 8)		12.2		6.8		11.0		5.2
Equity in earnings of unconsolidated affiliates (Note 4)		7.6		8.6		18.3		19.3
Interest, net		(2.4)		(2.0)		(4.5)		(4.1)
Other income, net		0.2		2.2		—		2.2
		17.6		15.6		24.8		22.6
Project income		25.2		17.2		53.9		38.8
Administrative and other expenses (income):
Administration		5.8		6.6		11.9		16.0
Interest, net		51.2		24.6		67.8		50.3
Foreign exchange loss (gain)		2.6		4.8		22.5		(27.4)
Other income, net (Note 6)		0.3		(1.7)		(2.2)		(3.1)
		59.9		34.3		100.0		35.8
(Loss) income from continuing operations before income taxes		(34.7)		(17.1)		(46.1)		3.0
Income tax (benefit) expense (Note 9)		(18.4)		2.9		(16.8)		(1.7)
(Loss) income from continuing operations		(16.3)		(20.0)		(29.3)		4.7
Net income from discontinued operations, net of tax (Note 3)		—		33.6		—		21.1
Net (loss) income		(16.3)		13.6		(29.3)		25.8
Net loss attributable to noncontrolling interests		—		(3.4)		—		(11.0)
Net income attributable to preferred shares dividends of a subsidiary company		2.2		2.3		4.2		4.6
Net (loss) income attributable to Atlantic Power Corporation	$	(18.5)	$	14.7	$	(33.5)	$	32.2
Basic and diluted (loss) income per share: (Note 11)
Loss from continuing operations attributable to Atlantic Power Corporation	$	(0.15)	$	(0.18)	$	(0.28)	$	—
Income from discontinued operations, net of tax		—		0.30		—		0.26
Net (loss) income attributable to Atlantic Power Corporation	$	(0.15)	$	0.12	$	(0.28)	$	0.26
Weighted average number of common shares outstanding: (Note 11)
Basic		121.6		121.9		121.8		121.7
Diluted		121.6		122.1		121.8		121.9

Dividends per common share:	$	—	$	0.02	$	—	$	0.05

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(in millions of U.S. dollars)

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net (loss) income	$	(16.3)	$	13.6	$	(29.3)	$	25.8
Other comprehensive (loss) income, net of tax:
Unrealized (loss) gain on hedging activities	$	(0.2)	$	0.2	$	(0.7)	$	(0.4)
Net amount reclassified to earnings		0.2		0.1		0.4		0.4
Net unrealized gain (loss) on derivatives		—		0.3		(0.3)		—

Foreign currency translation adjustments		1.0		4.5		19.4		(30.6)
Other comprehensive income (loss), net of tax		1.0		4.8		19.1		(30.6)
Comprehensive (loss) income		(15.3)		18.4		(10.2)		(4.8)
Less: Comprehensive income (loss) attributable to noncontrolling interests		2.2		(1.1)		4.2		(6.4)
Comprehensive (loss) income attributable to Atlantic Power Corporation	$	(17.5)	$	19.5	$	(14.4)	$	1.6

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions of U.S. dollars)

(Unaudited)


	Six months ended
	June 30,
	2016		2015
Cash provided by operating activities:
Net (loss) income	$	(29.3)	$	25.8
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization		50.3		66.4
Gain from discontinued operations		—		(47.3)
Gain on sale of development project and other assets		—		(2.3)
Gain on purchase and cancellation of convertible debentures		(2.5)		(3.0)
Loss on disposal of fixed assets		0.2		—
Stock-based compensation expense		0.8		1.0
Equity in earnings from unconsolidated affiliates		(18.3)		(19.3)
Distributions from unconsolidated affiliates		23.5		27.0
Unrealized foreign exchange loss (gain)		22.5		(27.6)
Change in fair value of derivative instruments		(11.0)		(4.5)
Change in deferred income taxes		(18.6)		20.4
Change in other operating balances
Accounts receivable		(3.3)		0.6
Inventory		(0.4)		2.8
Prepayments and other assets		39.2		9.3
Accounts payable		3.5		(3.4)
Accruals and other liabilities		(2.9)		7.5
Cash provided by operating activities:		53.7		53.4
Cash provided by investing activities:
Change in restricted cash		0.9		4.9
Proceeds from sale of assets and equity investments, net		—		326.3
Contribution to unconsolidated affiliate		—		(0.6)
Capitalized development costs		—		(0.8)
Reimbursement of costs for third-party construction project		4.7		—
Purchase of property, plant and equipment		(2.0)		(5.0)
Cash provided by investing activities		3.6		324.8
Cash provided by (used in) financing activities:
Proceeds from senior secured term loan facility, net of discount		679.0		—
Common share repurchases		(4.7)		—
Repayment of corporate and project-level debt		(502.7)		(62.2)
Repayment of convertible debentures		(127.0)		(18.0)
Deferred financing costs		(15.9)		—
Dividends paid to common shareholders		—		(5.8)
Dividends paid to noncontrolling interests		—		(3.8)
Dividends paid to preferred shareholders		(4.2)		(4.6)
Cash provided by (used in) financing activities		24.5		(94.4)
Net increase in cash and cash equivalents		81.8		283.8
Cash and cash equivalents at beginning of period at discontinued operations		—		3.9
Cash and cash equivalents at beginning of period		72.4		106.1
Cash and cash equivalents at end of period	$	154.2	$	393.8
Supplemental cash flow information
Interest paid	$	34.7	$	46.3
Income taxes paid, net	$	1.9	$	1.7
Accruals for construction in progress	$	1.0	$	—

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

1. Nature of business

General

Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long‑term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of June 30, 2016, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in twenty-three operational power generation projects across eleven states in the United States and two provinces in Canada. Eighteen of our projects are majority‑owned subsidiaries.

Atlantic Power is a corporation established under the laws of the Province of Ontario on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange under the symbol “ATP” and on the New York Stock Exchange under the symbol “AT.” Our registered office is located at 215-10451 Shellbridge Way, Richmond, British Columbia V6X 2W8 Canada and our headquarters is located at 3 Allied Drive, Suite 220, Dedham, Massachusetts 02026, USA. Our telephone number in Dedham is (617) 977‑2400 and the address of our website is www.atlanticpower.com. Information contained on Atlantic Power’s website or that can be accessed through its website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10‑Q. We have included our website address only as an inactive textual reference and do not intend it to be an active link to our website. We make available on our website, free of charge, our Annual Report on Form 10‑K, Quarterly Reports on Form 10‑Q, Current Reports on Form 8‑K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). Additionally, we make available on our website our Canadian securities filings, which are not incorporated by reference into our Exchange Act filings.

Basis of presentation

The interim consolidated financial statements included in this Quarterly Report on Form 10‑Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10‑Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10‑K for the year ended December 31, 2015. Interim results are not necessarily indicative of results for the full year.

In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of June 30, 2016, the results of operations and comprehensive (loss) income for the three and six months ended June 30, 2016 and 2015, and our cash flows for the six months ended June 30, 2016 and 2015 in accordance with U.S generally accepted accounting policies. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.

Use of estimates

The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and equity-based compensation. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10 K for the year ended December 31, 2015. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Recently issued accounting standards

Adopted

In January 2015, the Financial Accounting Standards Board (“FASB”) issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity’s statement of operations, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes became effective for us on January 1, 2016. The adoption of these changes did not have an impact on the consolidated financial statements.

In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes became effective for us on January 1, 2016. The adoption of these changes did not have an impact on the consolidated financial statements.

In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are required to be presented as a noncurrent asset in an entity’s balance sheet and amortized into interest expense over the term of the related debt instrument. The changes require that debt issuance costs be presented in an entity’s balance sheet as a direct deduction from the carrying value of the related debt liability. The amortization of debt issuance costs remains unchanged. These changes became effective for us on January 1, 2016. As a result, we have presented $22.2 million and $42.5 million of deferred financing costs as a direct deduction from long-term debt and convertible debentures for the periods ended June 30, 2016 and December 31, 2015, respectively.

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the statement of operations or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements became effective for us beginning January 1, 2016. We will apply this new guidance to any future business combinations.

Issued

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements and which implementation approach to select.

In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The changes require that inventory be measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on January 1, 2017. Management has determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by these changes. The new guidance will be effective for us in fiscal years beginning after December 15, 2016 and is not expected to have a material impact on the consolidated financial statements.

In February 2016, the FASB issued authoritative guidance intended to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a right-of-use asset and a lease liability, measured on a discounted basis, at the commencement date for all leases with terms greater than twelve months. Additionally, this guidance will require disclosures to help investors and other financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The guidance should be applied under a modified retrospective transition approach for leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. This guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

In March 2016, the FASB issued authoritative guidance intended to simplify and improve several aspects of the accounting for share-based payment transactions. The new guidance includes amendments to share-based accounting for income taxes, including adjustments to how excess tax benefits and a company's payments for tax withholdings should be classified in the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

2. Changes in accumulated other comprehensive loss by component

The changes in accumulated other comprehensive loss by component were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Foreign currency translation
Balance at beginning of period	$	(120.7)	$	(101.4)	$	(139.1)	$	(66.3)
Other comprehensive income (loss):
Foreign currency translation adjustments(1)		1.0		4.5		19.4		(30.6)
Balance at end of period	$	(119.7)	$	(96.9)	$	(119.7)	$	(96.9)
Pension
Balance at beginning of period	$	(0.4)	$	(2.1)	$	(0.4)	$	(2.1)
Other comprehensive income (loss):
Unrecognized net actuarial gain (loss)		—		—		—		—
Tax benefit (expense)		—		—		—		—
Total Other comprehensive (loss) income before reclassifications, net of tax		—		—		—		—
Amortization of net actuarial loss		—		—		—		—
Tax benefit		—		—		—		—
Total amount reclassified from Accumulated other comprehensive loss, net of tax		—		—		—		—
Total Other comprehensive (loss) income		—		—		—		—
Balance at end of period	$	(0.4)	$	(2.1)	$	(0.4)	$	(2.1)
Cash flow hedges
Balance at beginning of period	$	(0.1)	$	(0.2)	$	0.2	$	0.1
Other comprehensive income (loss):
Net change from periodic revaluations		(0.3)		0.2		(1.1)		(0.3)
Tax benefit (expense)		0.1		(0.1)		0.4		0.1
Total Other comprehensive income before reclassifications, net of tax		(0.2)		0.1		(0.7)		(0.2)
Net amount reclassified to earnings:
Interest rate swaps(2)		0.3		0.3		0.6		0.6
Tax expense		(0.1)		(0.1)		(0.2)		(0.4)
Total amount reclassified from Accumulated other comprehensive loss, net of tax		0.2		0.2		0.4		0.2
Total Other comprehensive income		—		0.3		(0.3)		—
Balance at end of period	$	(0.1)	$	0.1	$	(0.1)	$	0.1

⁽¹⁾

In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss).

⁽²⁾

This amount was included in Interest expense, net on the accompanying consolidated statements of operations.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

3. Discontinued operations

On June 26, 2015, Atlantic Power Transmission, Inc. (“APT”), our wholly-owned, direct subsidiary, sold our Wind Projects under a definitive agreement (the “Purchase Agreement”) with TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc. (an affiliate of TerraForm Power, Inc.). The sale was completed for aggregate cash proceeds of approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded a $47.0 million gain on sale, which is included as a component of income from discontinued operations in the consolidated statements of operations for the three and six months ended June 30, 2015.

Terraform acquired from APT, 100% of APT’s direct membership interests in a holding company formed to facilitate the sale, thereby acquiring our indirect interests in our portfolio of Wind Projects consisting of five operating wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest), Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50% economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest). As a result of the sale, we deconsolidated approximately $249 million of project debt (or approximately $274 million as adjusted for our proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $224 million of non-controlling interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian Hills.

The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the date we established a firm commitment to a plan to sell the wind assets. Our determination to designate the Wind Projects as discontinued operations was based on the impact the sale would have on our operations and financial results and because the Wind Projects made up the entirety of our Wind reportable Segment. We stopped depreciating the property, plant and equipment of the Wind Projects on the designation date.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

The following table summarizes the revenue and income from operations of the Wind Projects for the three and six months ended June 30, 2015:


	Three months		Six months
	ended		ended
	June 30,		June 30,
	2015		2015
Revenue	$	18.1	$	34.8
Project expenses:
Operations and maintenance		5.2		10.8
Depreciation and amortization		0.1		10.3
		5.3		21.1
Project other expense:
Change in fair value of derivatives		6.7		(0.7)
Equity in earnings of unconsolidated affiliates		0.7		(0.2)
Interest expense, net		(3.3)		(6.7)
Gain on sale of asset		47.3		47.3
		51.4		39.7
Income from operations of discontinued businesses		64.2		53.4
Income tax expense		30.6		32.3
Income from operations of discontinued businesses, net of tax		33.6		21.1
Net loss attributable to noncontrolling interests of discontinued businesses		(3.4)		(11.0)
Income from operations of discontinued businesses, net of noncontrolling interests	$	37.0	$	32.1

Basic and diluted earnings per share related to income from discontinued operations for the Wind Projects was $0.30 and $0.26 for the three and six months ended June 30, 2015, respectively.

The following table summarizes the operating and investing cash flows of the Wind Projects for the six months ended June 30, 2015:


	Six months
	ended
	June 30,
	2015
Cash provided by operating activities	$	21.9
Cash provided by investing activities		(12.8)

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

4. Equity method investments in unconsolidated affiliates

The following summarizes the operating results for the three and six months ended June 30, 2016 and 2015, respectively, for our equity method investments:


	Three Months Ended June 30,				Six Months Ended June 30,
Operating results	2016		2015		2016		2015
Revenue
Chambers	$	10.4	$	10.9	$	23.1	$	26.3
Frederickson		4.8		5.4		9.9		10.1
Orlando		13.2		14.1		26.7		26.9
Other(1)		2.2		2.6		4.0		7.5
		30.6		33.0		63.7		70.8
Project expenses
Chambers		9.7		9.6		18.5		20.9
Frederickson		4.9		4.9		9.4		9.0
Orlando		6.0		6.7		12.6		13.3
Other(1)		1.9		2.7		4.0		7.4
		22.5		23.9		44.5		50.6
Project other expense
Chambers		(0.5)		(0.5)		(0.9)		(0.9)
Frederickson		—		—		—		—
Orlando		—		—		—		—
Other(1)		—		—		—		—
		(0.5)		(0.5)		(0.9)		(0.9)
Project income (loss)
Chambers	$	0.2	$	0.8	$	3.7	$	4.5
Frederickson		(0.1)		0.5		0.5		1.1
Orlando		7.2		7.4		14.1		13.6
Other(1)		0.3		(0.1)		—		0.1
		7.6		8.6		18.3		19.3

⁽¹⁾

Includes equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

5. Long‑term debt

Long‑term debt consists of the following:


	June 30,		December 31,
	2016		2015		Interest Rate
Recourse Debt:
Senior secured term loan facility, due 2021	$	—	$	473.2	LIBOR(1)	plus	3.75	%
Senior secured term loan facility, due 2023		674.9		—	LIBOR(1)	plus	5.00	%
Senior unsecured notes, due June 2036 (Cdn$210.0)		162.6		151.7			5.95	%
Non-Recourse Debt:
Epsilon Power Partners term facility, due 2019		16.5		19.5	LIBOR	plus	3.125	%
Cadillac term loan, due 2025		28.3		29.5	LIBOR	plus	1.37	%
Piedmont term loan, due 2018		59.0		59.0			8.47	%
Other long-term debt		0.2		0.4	5.50	% -	6.70	%
Less: unamortized discount		(19.7)		—
Less: unamortized deferred financing costs		(17.6)		(34.8)
Less: current maturities		(96.4)		(15.8)
Total long-term debt	$	807.8	$	682.7

Current maturities consist of the following:


	June 30,		December 31,
	2016		2015		Interest Rate
Current Maturities:
Senior secured term loan facility, due 2021	$	—	$	4.7	LIBOR(1)	plus	3.75	%
Senior secured term loan facility, due 2023(2)		84.9		—	LIBOR(1)	plus	5.00	%
Epsilon Power Partners term facility, due 2019		6.1		6.0	LIBOR	plus	3.125	%
Cadillac term loan, due 2025		2.8		2.5	LIBOR	plus	1.37	%
Piedmont term loan, due 2018		2.4		2.4			8.47	%
Other short-term debt		0.2		0.2	5.50	% -	6.70	%
Total current maturities	$	96.4	$	15.8

⁽¹⁾

LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $444.4 million of the $674.9 million outstanding aggregate borrowings under our senior secured term loan facility at June 30, 2016. See Note 8, Accounting for derivative instruments and hedging activities for further details.

⁽²⁾

On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the credit agreement and disclosed below. The portion of the senior secured term loan facility classified as current is based on principal payments required to reduce the aggregate principal amount of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

New Credit Facilities

On April 13, 2016, APLP Holdings Limited Partnership (“APLP Holdings”), our wholly-owned subsidiary, entered into new senior secured credit facilities, comprising $700 million in aggregate principal amount of senior secured term loan facilities (the “New Term Loans”) and $200 million in aggregate principal amount of senior secured revolving credit facilities (the “New Revolver” and together with the New Term Loans, the “New Credit Facilities”). On the same date, $700 million was drawn under the New Term Loan, bearing interest at the Adjusted Eurodollar Rate plus the applicable margin of 5.00%, and letters of credit in an aggregate face amount of $105.8 million were issued (but not drawn) pursuant to the revolving commitments under the New Revolver and used (i) to fund a debt service reserve in an amount equivalent to six months of debt service (approximately $25.3 million), and (ii) to support contractual credit support obligations of APLP Holdings and its subsidiaries and of certain other affiliates of the Company. The New Revolver matures in April 2021 and the New Term Loans mature in April 2023. We received $679.0 million in proceeds after an original issue discount of 3% ($21.0 million).

We have used the $679.0 million proceeds from the New Term Loans to:

 redeem in whole, at a price equal to par plus accrued interest, APLP’s existing senior secured term loan, maturing in February 2021, in an aggregate principal amount outstanding of $447.9 million (see “Senior Secured Credit Facilities” below);

 redeem in whole, at a price equal to par plus accrued interest (i) our outstanding Cdn$67.2 million 6.25% Convertible Unsecured Subordinated Debentures, Series A, maturing in March 2017 (the “Series A Debentures”) and (ii) our outstanding Cdn$75.8 million 5.60% Convertible Unsecured Subordinated Debentures, Series B, maturing in June 2017 (the “Series B Debentures”) (total US$ equivalent of $110.7 million);

 redeem, at a price equal to $965 per $1,000 principal amount plus accrued interest, $62.7 million of our 5.75% Convertible Unsecured Subordinated Debentures, Series C, maturing on June 30, 2019; and

 pay transaction costs and expenses of approximately $14.4 million.

We may use the remaining proceeds of approximately $43.0 million for any corporate purpose.

We accounted for the redemption of the Senior Secured Credit Facilities as an extinguishment of debt and wrote off $30.2 million of deferred financing costs to interest expense in the three months ended June 30, 2016.

Borrowings under the New Credit Facilities are available in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted Eurodollar Rate, the Base Rate or the Canadian Prime Rate as applicable, plus an applicable margin between 4.00% and 5.00% that varies depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The New Term Loans include a 3% original issue discount, and matures on April 12, 2023. The revolving commitments under the New Revolver terminate on April 12, 2021. Letters of credit are available to be issued under the New Revolver until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. In addition to paying interest on outstanding principal under the New Credit Facilities, APLP Holdings is required to pay a commitment fee with respect to the revolving commitments under the New Revolver that is equal to 0.75% times the average of the daily difference between (A) the revolving commitments and (B) drawings, if any and all outstanding reimbursement obligations with respect to drawn letters of credit.

The New Credit Facilities are secured by a pledge of the equity interests in APLP Holdings and certain of its subsidiaries, guaranties from certain of the subsidiaries of APLP Holdings (the “Subsidiary Guarantors”), a downstream guarantee from the Company, a limited recourse guaranty from Atlantic Power GP II, Inc., the entity that holds all of the equity interest in APLP Holdings, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment of all revenues, funds and accounts of APLP Holdings and its subsidiaries (subject to certain

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

exceptions), and certain other assets. The New Credit Facilities also have the benefit of a debt service reserve account, which is required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service. Atlantic Power Limited Partnership (“APLP”), a wholly-owned, indirect subsidiary of the Company, is a party to an existing indenture governing its Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due June 23, 2036 (the “MTNs”) that prohibits APLP (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness. Accordingly, in connection with the execution of the Credit Agreement, APLP Holdings has granted an equal and ratable security interest in the collateral package securing the New Credit Facilities in favor of the trustee under the indenture governing the MTNs for the benefit of the holders of the MTNs.

The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The negative covenants include a requirement that APLP Holdings and its subsidiaries maintain a Leverage Ratio (as defined in the Credit Agreement) ranging from 6.00:1.00 in 2016 to 4.25:1.00 from June 30, 2020, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 2.75:1.00 in 2016 to 4.00:1.00 from June 30, 2022. In addition, the Credit Agreement includes customary restrictions and limitations on APLP Holdings’ and its subsidiaries’ ability to (i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to certain exceptions and other customary carve-outs and various thresholds.

Under the Credit Agreement, if a Change of Control (as defined in the Credit Agreement) occurs, unless APLP Holdings elects to make a voluntary prepayment of the term loans under the New Credit Facilities, it will be required to offer each electing lender to prepay such lender’s term loans under the New Credit Facilities at a price equal to 101% of par. In addition, in the event that APLP Holdings elects to repay, prepay, refinance or replace all or any portion of the term loan facilities within one year from the initial funding date under the Credit Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid, refinanced or replaced.

The Credit Agreement also contains a mandatory amortization feature and other mandatory prepayment provisions, including prepayments:

 from the proceeds of asset sales (except from the sale proceeds of certain excluded projects), insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and

 in respect of excess cash flow, to be determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the New Credit Facilities and the MTNs, funding of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Credit Agreement, and payment on the preferred equity issued by Atlantic Power Preferred Equity Ltd., a subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate principal amount of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Failure to achieve the specified target principal amount for any quarter does not constitute a default by APLP Holdings.

Under certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

warranties in any material respect, non-payment or acceleration of other material debt of APLP Holdings and its subsidiaries, bankruptcy, material judgments rendered against APLP Holdings or certain of its subsidiaries, certain ERISA or regulatory events, a Change of Control of APLP Holdings (solely with respect to the New Revolver), or defaults under certain guaranties and collateral documents securing the New Credit Facilities, in each case subject to various exceptions and notice, cure and grace periods.

Senior Secured Credit Facilities

As noted above in “New Credit Facilities”, our senior secured credit facilities were redeemed on April 13, 2016. The redemption and extinguishment was recorded in the three months ended June 30, 2016.

Notes of Atlantic Power Corporation

On July 26, 2015, we redeemed all of our outstanding $310.9 million aggregate principal amount of 9.0% Senior Unsecured Notes due November 2018 (the “Notes”) with the cash proceeds received from the sale of the Wind Projects. The Notes were redeemed at a price equal to 104.5 percent of the principal amount of the 9.0% notes, plus accrued and unpaid interest to the redemption date. We paid $330.4 million to fund the full redemption of the Notes, which includes $14.0 million in make-whole premiums and $5.5 million in accrued interest. The make whole premiums, accrued interest and the $9.0 million of deferred financing costs related to the Notes were recorded in interest expense in the three and nine months ended September 30, 2015.

Non‑Recourse Debt

Project level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project level debt generally amortizes during the term of the respective revenue-generating contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available cash to Atlantic Power. At June 30, 2016, all of our projects with the exception of Piedmont were in compliance with the covenants contained in project level debt. Projects that do not meet their debt service coverage ratios are limited from making distributions, but the debt is not callable or subject to acceleration under the terms of their debt agreements. We do not expect our Piedmont project to meet its debt service coverage ratio covenants or to make distributions before the project’s debt maturity in 2018 at the earliest.

6. Convertible debentures

Convertible debentures consist of the following:




	June 30,		December 31,
	2016		2015
6.25% Debentures due March 2017	$	—	$	48.6
5.60% Debentures due June 2017		—		54.8
5.75% Debentures due June 2019		105.3		117.0
6.00% Debentures due December 2019 (Cdn$81.0 million)		62.7		65.0
Less: Unamortized deferred financing costs		(4.6)		(7.7)
Total convertible debentures	$	163.4	$	277.7

On November 11, 2014, we commenced a normal course issuer bid (“NCIB”) for our convertible debentures. Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures which expired on November 10, 2015. As of December 31, 2015, we had

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

repurchased and cancelled $24.8 million of convertible debentures and recorded a gain of $3.1 million in the consolidated statements of operations related to these transactions.

On December 29, 2015, we commenced a new NCIB, which will expire on December 28, 2016. The actual amount of convertible debentures that may be purchased under the NCIB is approximately $28.5 million and is further limited to 10% of the public float of our convertible debentures. Since inception of the NCIB in the fourth quarter of 2015 and through June 30, 2016, we repurchased and canceled $18.8 million of convertible debentures and recorded a gain of $2.5 million in the consolidated statement of operations for the six months ended June 30, 2016.

On April 13, 2016, we deposited a portion of the proceeds from the issuance of the New Credit Facilities, for the redemption in whole on May 13, 2016 at a price equal to par plus accrued interest (i) the outstanding Cdn$67.2 million 6.25% Debentures due March 2017 and (ii) the outstanding Cdn$75.8 million 5.60% Debentures due June 2017 (total US$ equivalent of $110.7 million as of April 13, 2016). Deferred financing costs related to the debentures of $1.3 million were written off and recorded to interest expense in April 2016.

On June 17, 2016, we commenced a substantial issuer bid to purchase for cancellation up to $65.0 million aggregate principal amount of our issued and outstanding 5.75% Series C Convertible Unsecured Subordinated Debentures maturing June 30, 2019. The offer expired on July 22, 2016. An aggregate of $62.7 million principal amount of the debentures were purchased and cancelled under the offer. As of August 4, 2016 there were approximately $42.6 million principal amount of Series C debentures outstanding. We will record a gain of approximately $1.3 million related to the repurchase in the consolidated statements of operations for the three and nine months ended September 30, 2016.

7. Fair value of financial instruments

The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of June 30, 2016 and December 31, 2015. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.


	June 30, 2016
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	154.2	$	—	$	—	$	154.2
Restricted cash		14.3		—		—		14.3
Derivative instruments asset		—		2.7		—		2.7
Total	$	168.5	$	2.7	$	—	$	171.2
Liabilities:
Derivative instruments liability	$	—	$	52.1	$	—	$	52.1
Total	$	—	$	52.1	$	—	$	52.1


	December 31, 2015
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	72.4	$	—	$	—	$	72.4
Restricted cash		15.2		—		—		15.2
Derivative instruments asset		—		0.3		—		0.3
Total	$	87.6	$	0.3	$	—	$	87.9
Liabilities:
Derivative instruments liability	$	—	$	57.5	$	—	$	57.5
Total	$	—	$	57.5	$	—	$	57.5

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a risk free interest rate.

We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of June 30, 2016, the credit valuation adjustments resulted in a $5.3 million net increase in fair value, which consists of a $0.6 million pre‑tax gain in other comprehensive income and a $4.7 million gain in change in fair value of derivative instruments. As of December 31, 2015, the credit valuation adjustments resulted in a $3.8 million net increase in fair value, which consists of a $0.4 million pre‑tax gain in other comprehensive income and a $3.4 million gain in change in fair value of derivative instruments.

The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.

8. Accounting for derivative instruments and hedging activities

We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value in each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.

Gas purchase agreements

Gas purchase agreements to purchase gas forward at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through their expiration in the fourth quarter of 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.

In June 2014, APLP entered into contracts for the purchase of 2.9 million Gigajoules (“Gj”) of future natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 100% of our expected uncontracted gas requirements for 2015 and 35% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.

We have entered into various natural gas sales and purchase agreements for approximately 1,302,000 MMBtu to effectively mitigate seasonal fluctuation of future natural gas price at Morris through March 2017. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2016. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

Natural gas swaps

Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.

We have entered into various natural gas swaps to effectively fix the price of 5.7 million Mmbtu of future natural gas purchases at Orlando, which is approximately 95% of our share of the expected natural gas purchases at the project through December 2017. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2016. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.

Interest rate swaps

On May 5, 2014, APLP entered into several interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount ($134.4 million at June 30, 2016) of the $600 million aggregate principal amount of borrowings under the Term Loan Facility, which had entered on February 24, 2014 and redeemed in whole on May 2016. The interest rate swap agreements were effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the consolidated statements of operations. These interest rate swap agreements were novated to APLP Holdings.

APLP Holdings has entered into several interest rate swap agreements to mitigate its exposure to changes in interest at the Adjusted Eurodollar Rate for $310.0 million notional amount of the $700.0 million aggregate principal amount ($674.9 million at June 30, 2016) of borrowings under the New Term Loans in addition to previously entered interest rate swap agreements for the notional amount of $199.0 million ($134.4 million at June 30, 2016) under the Term Loan Facility. The new agreements were entered into on May 25, 2016 and June 28, 2016 for the notional amounts of $150.0 million and $160.0 million, and terminate on March 31, 2020 and September 30, 2019, respectively.

Borrowings under the $700.0 million New Term Loans bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 5.00%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 6.00% all-in rate on the Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $509.0 million of the New Term Loans cannot be less than 6.00%, if the Adjusted Eurodollar Rate is equal to or greater than 1.00%.

The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable‑rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all‑in rate of 8.5%. The swap continues at the fixed rate of 4.47% until November 2030. Prior to conversion of the Piedmont construction loan facility to a term loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of Piedmont’s construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac’s debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive loss.

Volume of forecasted transactions

We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption at June 30, 2016 and December 31, 2015:


		June 30,	December 31,
	Units	2016	2015
Natural gas swaps	Natural Gas (Mmbtu)	5.7	2.8
Gas purchase agreements	Natural Gas (Gigajoules)	19.4	25.0
Interest rate swaps	Interest (US$)	532.3	302.3

Fair value of derivative instruments

We have elected to disclose derivative instrument assets and liabilities on a trade‑by‑trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:


	June 30, 2016
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	1.0
Interest rate swaps long-term		—		3.2
Total derivative instruments designated as cash flow hedges		—		4.2
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		—		3.3
Interest rate swaps long-term		—		12.4
Natural gas swaps current		1.6		1.9
Natural gas swaps long-term		1.1		—
Gas purchase agreements current		—		17.4
Gas purchase agreements long-term		—		12.9
Total derivative instruments not designated as cash flow hedges		2.7		47.9
Total derivative instruments	$	2.7	$	52.1

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)


	December 31, 2015
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	1.0
Interest rate swaps long-term		—		2.7
Total derivative instruments designated as cash flow hedges		—		3.7
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		—		2.0
Interest rate swaps long-term		0.3		7.8
Natural gas swaps current		—		5.0
Natural gas swaps long-term		—		—
Gas purchase agreements current		—		28.7
Gas purchase agreements long-term		—		10.3
Total derivative instruments not designated as cash flow hedges		0.3		53.8
Total derivative instruments	$	0.3	$	57.5

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

Accumulated other comprehensive income

The following table summarizes the changes in the accumulated other comprehensive income (loss) (“OCI”) balance attributable to derivative financial instruments designated as a hedge, net of tax:


	Interest Rate
Three Months Ended June 30, 2016	Swaps
Accumulated OCI balance at March 31, 2016	$	(0.1)
Change in fair value of cash flow hedges		(0.2)
Realized from OCI during the period		0.2
Accumulated OCI balance at June 30, 2016	$	(0.1)

	Interest Rate
Three Months Ended June 30, 2015	Swaps
Accumulated OCI balance at March 31, 2015	$	(0.2)
Change in fair value of cash flow hedges		0.2
Realized from OCI during the period		0.1
Accumulated OCI balance at June 30, 2015	$	0.1

	Interest Rate
Six Months Ended June 30, 2016	Swaps
Accumulated OCI balance at January 1, 2016	$	0.2
Change in fair value of cash flow hedges		(0.7)
Realized from OCI during the period		0.4
Accumulated OCI balance at June 30, 2016	$	(0.1)

	Interest Rate
Six Months Ended June 30, 2015	Swaps
Accumulated OCI balance at January 1, 2015	$	0.1
Change in fair value of cash flow hedges		(0.4)
Realized from OCI during the period		0.4
Accumulated OCI balance at June 30, 2015	$	0.1

Impact of derivative instruments on the consolidated statements of operations

The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow hedges:



	Classification of loss (gain)	Three Months Ended June 30,				Six Months Ended June 30,
	recognized in income	2016		2015		2016		2015
Gas purchase agreements	Fuel	$	12.5	$	12.3		24.0	$	24.2
Natural gas swaps	Fuel		1.3		1.6		3.3		3.0
Interest rate swaps	Interest, net		1.1		1.0		1.7		1.9

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

The following table summarizes the unrealized loss (gain) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:


	Classification of gain (loss)	Three Months Ended June 30,				Six Months Ended June 30,
	recognized in income	2016		2015		2016		2015
Natural gas swaps	Change in fair value of derivatives	$	4.0	$	1.4	$	5.8	$	0.8
Gas purchase agreements	Change in fair value of derivatives		11.4		3.9		11.2		5.6
Interest rate swaps	Change in fair value of derivatives		(3.2)		1.5		(6.0)		(1.2)
		$	12.2	$	6.8	$	11.0	$	5.2

9. Income taxes


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Current income tax expense	$	0.3	$	6.2	$	1.8	$	7.3
Deferred tax benefit		(18.7)		(3.3)		(18.6)		(9.0)
Total income tax (benefit) expense, net	$	(18.4)	$	2.9	$	(16.8)	$	(1.7)

For the three and six months ended June 30, 2016 and 2015

Income tax benefit for the three months ended June 30, 2016 was $18.4 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26% was $9.0 million. The primary items impacting the tax rate for the three months ended June 30, 2016 were $4.6 million related to capital gain on intercompany notes, $2.6 million related to foreign exchange, $1.8 million relating to a change in the valuation allowance and $0.4 million of other permanent differences. These items were partially offset by $18.8 million related to capital loss recognized on tax restructuring.

Income tax expense for the three months ended June 30, 2015 was $2.9 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $4.4 million. The primary items impacting the tax rate for the three months ended June 30, 2015 were $9.0 million relating to a change in the valuation allowance, $3.4 million of dividend withholding and other state taxes, and $2.5 million of other permanent differences. These items were partially offset by $3.6 million relating to tax credits, $2.4 million relating to foreign exchange and $1.6 million relating to operating in higher tax rate jurisdictions.

Income tax benefit for the six months ended June 30, 2016 was $16.8 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $12.0 million. The primary items impacting the tax rate for the six months ended June 30, 2016 were $5.1 million relating to foreign exchange, $4.6 million relating to a change in the valuation allowance, $4.2 million related to capital gain on intercompany notes and $0.1 million of other permanent differences. These items were partially offset by $18.8 million related to capital loss recognized on tax restructuring.

Income tax benefit for the six months ended June 30, 2015 was $1.7 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $0.8 million. The primary items impacting the tax rate for the six months ended June 30, 2015 were $4.1 million relating to foreign exchange, $4.0 million relating to operating in higher tax rate jurisdictions, $3.6 million related to tax credits, and $0.6 million of other permanent

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

differences. These items were partially offset by $6.2 million relating to a change in the valuation allowance, and $3.6 million relating to dividend withholding and other taxes.

As of June 30, 2016, we have recorded a valuation allowance of $179.8 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

10. Equity compensation plans

Long‑term incentive plan (“LTIP”)

The following table summarizes the changes in outstanding LTIP notional units during the six months ended June 30, 2016:


		Grant Date
		Weighted-Average
	Units	Fair Value per Unit
Outstanding at December 31, 2015	1,298,401	$	2.88
Granted	1,594,954		1.81
Vested and redeemed	(771,437)		2.85
Forfeitures	(7,431)		2.71
Outstanding at June 30, 2016	2,114,487	$	2.08

Cash payments made for vested notional units for the six months ended June 30, 2016 and 2015 were $0.4 million and $0.6 million, respectively. Compensation expense for LTIP was $0.8 million and $0.9 million for the three and six months ended June 30, 2016, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2015, respectively.

Transition Equity Participation Agreement

We also have 539,904 transition notional shares outstanding at June 30, 2016 under the Transition Equity Participation Agreement with James J. Moore, Jr. Fifty percent of the transition notional shares granted with respect to fiscal year 2015 will vest upon the four-year anniversary of the date of grant and the remaining portion will vest on or any time after the two-year anniversary of the grant if the weighted average Canadian dollar closing price of our common shares on the TSX for at least three consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015(Cdn$3.18) by at least 50%.

11. Basic and diluted earnings (loss) per share

Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP.

Because we reported a loss for the three and six months ended June 30, 2016, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and six months ended June 30, 2016 and 2015:


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Numerator:
Loss from continuing operations attributable to Atlantic Power Corporation	$	(18.5)	$	(22.3)	$	(33.5)	$	0.1
Income from discontinued operations, net of tax		—		37.0		—		32.1
Net (loss) income attributable to Atlantic Power Corporation	$	(18.5)	$	14.7	$	(33.5)	$	32.2
Denominator:
Weighted average basic shares outstanding		121.6		121.9		121.8		121.7
Dilutive potential shares:
Convertible debentures		14.8		22.6		18.3		23.0
LTIP notional units		0.1		0.2		0.1		0.2
Potentially dilutive shares		136.5		144.7		140.2		144.9
Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.15)	$	(0.18)	$	(0.28)	$	—
Diluted earnings per share from discontinued operations		—		0.30		—		0.26
Diluted (loss) earnings per share attributable to Atlantic Power Corporation	$	(0.15)	$	0.12	$	(0.28)	$	0.26

The dilutive effect of our convertible debentures is calculated using the “if-converted method.” Under the if-converted method, the debentures are assumed to be converted at the beginning of the period, and the resulting common shares are included in the denominator of the diluted EPS calculation for the entire period being presented. Interest expense, net of any income tax effects, is added back to the numerator for purposes of the if-converted calculation. Potentially dilutive shares from convertible debentures of $14.8 million and $18.3 million have been excluded from fully diluted shares in the three and six months ended June 30, 2016, respectively, because their impact would be anti-dilutive. Potentially dilutive shares from convertible debentures of $22.6 million and $23.0 million have been excluded from fully diluted shares in the three and six months ended June 30, 2015, respectively, because their impact would be anti-dilutive.

12. Equity

The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the six months ended June 30, 2016 and 2015:

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)


	Six months ended June 30, 2016
	Total Atlantic		Preferred shares
	Power Corporation		issued by a subsidiary
	Shareholders’ Equity		company		Total Equity
Balance at January 1, 2016	$	213.9	$	221.3	$	435.2
Net (loss) income		(33.5)		4.2		(29.3)
Realized and unrealized loss on hedging activities, net of tax		(0.3)		—		(0.3)
Foreign currency translation adjustment		19.4		—		19.4
Common share repurchases		(4.7)		—		(4.7)
Stock-based compensation		0.8		—		0.8
Dividends declared on preferred shares of a subsidiary company		—		(4.2)		(4.2)
Balance at June 30, 2016	$	195.6	$	221.3	$	416.9


	Six months ended June 30, 2015
	Total Atlantic		Preferred shares
	Power Corporation		issued by a subsidiary		Noncontrolling
	Shareholders’ Equity		company		Interests		Total Equity
Balance at January 1, 2015	$	356.2	$	221.3	$	239.0	$	816.5
Net income (loss)		32.2		4.6		(11.0)		25.8
Foreign currency translation adjustment		(30.6)		—		—		(30.6)
Stock-based compensation		1.0		—		—		1.0
Dividends paid to noncontrolling interest		—		—		(3.7)		(3.7)
Dividends declared on common shares		(5.8)		—		—		(5.8)
Dividends declared on preferred shares of a subsidiary company		—		(4.6)		—		(4.6)
Derecognition of noncontrolling interests upon sale of subsidiaries		—		—		(224.3)		(224.3)
Balance at June 30, 2015	$	353.0	$	221.3	$	—	$	574.3

Stock Repurchase Program

In December 2015, our Board of Directors approved an NCIB for each series of our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd (“APPEL”), our wholly-owned subsidiary. The Board authorization permits the Company to repurchase stock through open market repurchases. The NCIB will expire on December 28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. From inception of the NCIB through June 30, 2016, we repurchased a cumulative 2,025,080 common shares at a total cost of $4.7 million. Repurchases and retirement of common shares are recorded to common shares on the consolidated balance sheets.

13. Segment and geographic information

We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We revised our reportable business segments in the second quarter of 2015 as the result of significant asset sales and in order to align with changes in management’s structure, resource allocation and performance assessment in making decisions regarding our operations. The Wind Projects, which made up the entirety of the former Wind segment, were sold in June 2015 and

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

are designated as discontinued operations for the three and six months ended June 30, 2015. We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Our equity investments in unconsolidated affiliates are presented as proportionately consolidated based on our ownership percentage in the reconciliation of Project Adjusted EBITDA to project income (loss).

A reconciliation of Net income (loss) from continuing operations to Project Adjusted EBITDA for the three and six months ended June 30, 2016 and 2015 is included in the table below:


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Three Months Ended June 30, 2016
Project revenues	$	33.7	$	25.5	$	38.8	$	0.2	$	98.2
Segment assets		787.1		335.9		430.3		168.0		1,721.3
Net income (loss) from continuing operations		9.6		4.6		12.9		(43.4)		(16.3)
Income tax benefit		—		—		—		(18.4)		(18.4)
Income (loss) from continuing operations before income taxes		9.6		4.6		12.9		(61.8)		(34.7)
Administration		—		—		—		5.8		5.8
Interest, net		—		—		—		51.2		51.2
Foreign exchange loss		—		—		—		2.6		2.6
Other income, net		—		—		—		0.3		0.3
Project income (loss)	$	9.6	$	4.6	$	12.9	$	(1.9)	$	25.2
Change in fair value of derivative instruments		(2.5)		—		(11.6)		1.9		(12.2)
Depreciation and amortization		10.9		9.9		9.6		—		30.4
Interest, net		2.9		—		—		—		2.9
Other project expense		—		—		—		(0.1)		(0.1)
Project Adjusted EBITDA	$	20.9	$	14.5	$	10.9	$	(0.1)	$	46.2

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Three Months Ended June 30, 2015
Project revenues	$	38.9	$	26.3	$	37.7	$	0.2	$	103.1
Segment assets		858.6		375.8		612.8		452.7		2,299.9
Net income (loss) from continuing operations	$	16.7	$	(4.3)	$	2.8	$	(35.2)	$	(20.0)
Income tax expense		—		—		—		2.9		2.9
Income (loss) from continuing operations before income taxes		16.7		(4.3)		2.8		(32.3)		(17.1)
Administration		—		—		—		6.6		6.6
Interest, net		—		—		—		24.6		24.6
Foreign exchange gain		—		—		—		4.8		4.8
Other income, net		—		—		—		(1.7)		(1.7)
Project income (loss)	$	16.7	$	(4.3)	$	2.8	$	2.0	$	17.2
Change in fair value of derivative instruments		(3.0)		—		(3.9)		—		(6.9)
Depreciation and amortization		10.8		10.0		12.7		(0.2)		33.3
Interest, net		2.5		—		—		—		2.5
Other project expense (income)		—		—		—		(2.2)		(2.2)
Project Adjusted EBITDA	$	27.0	$	5.7	$	11.6	$	(0.4)	$	43.9


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Six Months Ended June 30, 2016
Project revenues	$	73.1	$	44.5	$	86.5	$	0.5	$	204.6
Segment assets		787.1		335.9		430.3		168.0		1,721.3
Net income (loss) from continuing operations	$	25.6	$	2.3	$	29.3	$	(86.5)	$	(29.3)
Income tax benefit		—		—		—		(16.8)		(16.8)
Income (loss) from continuing operations before income taxes		25.6		2.3		29.3		(103.3)		(46.1)
Administration		—		—		—		11.9		11.9
Interest, net		—		—		—		67.8		67.8
Foreign exchange loss		—		—		—		22.5		22.5
Other income, net		—		—		—		(2.2)		(2.2)
Project (loss) income	$	25.6	$	2.3	$	29.3	$	(3.3)	$	53.9
Change in fair value of derivative instruments		(1.7)		—		(12.1)		2.8		(11.0)
Depreciation and amortization		21.9		19.7		18.5		0.2		60.3
Interest, net		5.4		—		—		—		5.4
Other project expense		—		—		—		0.1		0.1
Project Adjusted EBITDA	$	51.2	$	22.0	$	35.7	$	(0.2)	$	108.7

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Six Months Ended June 30, 2015
Project revenues	$	76.5	$	49.3	$	88.2	$	0.4	$	214.4
Segment assets		858.6		375.8		612.8		452.7		2,299.9
Net (loss) income from continuing operations	$	28.0	$	(4.0)	$	16.0	$	(35.3)	$	4.7
Income tax benefit		—		—		—		(1.7)		(1.7)
(Loss) income from continuing operations before income taxes		28.0		(4.0)		16.0		(37.0)		3.0
Administration		—		—		—		16.0		16.0
Interest, net		—		—		—		50.3		50.3
Foreign exchange loss		—		—		—		(27.4)		(27.4)
Other income, net		—		—		—		(3.1)		(3.1)
Project (loss) income		28.0	$	(4.0)	$	16.0	$	(1.2)		38.8
Change in fair value of derivative instruments		(0.4)		—		(5.5)		0.8		(5.1)
Depreciation and amortization		21.2		19.6		24.9		0.4		66.1
Interest, net		4.9		—		—		—		4.9
Other project expense		—		—		—		(2.2)		(2.2)
Project Adjusted EBITDA	$	53.7	$	15.6	$	35.4	$	(2.2)	$	102.5

The table below provides information, by country, about our consolidated operations for each of the three and six months ended June 30, 2016 and 2015 and Property, Plant & Equipment as of June 30, 2016 and December 31, 2015, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.



	Project Revenue Three Months Ended June 30,				Project Revenue Six Months Ended June 30,				Property, Plant and Equipment, net of accumulated depreciation
	2016		2015		2016		2015		June 30, 2016		December 31, 2015
United States	$	59.4	$	65.4	$	118.1	$	126.2	$	510.5	$	529.6
Canada		38.8		37.7		86.5		88.2		257.6		248.1
Total	$	98.2	$	103.1	$	204.6	$	214.4	$	768.1	$	777.7

Independent Electricity System Operator (“IESO”), BC Hydro and San Diego Gas & Electric provided 31%, 14%, and 11%, respectively, of total consolidated revenues for the three months ended June 30, 2016. IESO, BC Hydro and Niagara Mohawk provided 35%, 14% and 9% respectively, of total consolidated revenues for the six months ended June 30, 2016. IESO, San Diego Gas & Electric, BC Hydro and Niagara Mohawk Power Corporation provided 26.4%, 12.5%, 10.3% and 10.9%, respectively, of total consolidated revenues for the three months ended June 30, 2015 and 30.2%, 10.6%, 11.0% and 8.6%, respectively, of total consolidated revenues for the six months ended June 31, 2015. IESO purchases electricity from the Calstock, Kapuskasing, Nipigon and North Bay projects in the Canada segment, San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West U.S. segment, BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment and Niagara Mohawk purchases electricity from the Curtis Palmer project in the East U.S. segment.

14. Guarantees

We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements,

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

including the Purchase Agreement to sell the Wind Projects, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.

In connection with the Purchase Agreement for the sale of the Wind Projects, on June 30, 2015, we entered into a guaranty agreement, under which we agreed to guarantee the full and prompt payment of all payment obligations of APT under the Purchase Agreement as and when they shall become due. APT and TerraForm have agreed to utilize the representation and warranty insurance for coverage of certain indemnification obligations, subject to a cap and certain exclusions.

15. Contingencies

Shareholder class action lawsuits

On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec.

On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. This claim named the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs sought leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserted common law claims for misrepresentation.

The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015.

On July 24, 2015, the Ontario Superior Court of Justice issued a decision denying the Plaintiffs’ motion for leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial indemnity costs of responding to the Plaintiffs’ motion.

The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal.

The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs.

The proposed Quebec class action was suspended by the Superior Court of Quebec pending the outcome of the motions for leave and certification of the Ontario action as a class proceeding. On April 19, 2016, the Superior Court of Quebec authorized the discontinuance of the action.

Other

In addition to the matters listed above, from time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in millions U.S. dollars, except per‑share amounts)

(Unaudited)

which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of June 30, 2016.

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FORWARD‑LOOKING INFORMATION

Certain statements in this Quarterly Report on Form 10‑Q constitute “forward‑looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward‑looking statements generally can be identified by the use of forward‑looking terminology such as “outlook,” “objective,” “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “should,” “plans,” “continue,” or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly Report on Form 10‑Q include, but are not limited to, statements with respect to the following:

our ability to generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities;

the outcome or impact of our business plan, including the objective of enhancing the value of our existing assets through optimization investments and commercial activities, delevering our balance sheet to improve our cost of capital, improving our cost structure and reducing overhead;

our ability to access liquidity for the ongoing operation of our business and the execution of our business plan or any potential options, which may involve one or more of the use of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately‑placed bank or institutional non‑recourse operating level debt;

our ability to renew or enter into new power purchase agreements on favorable terms or at all after the expiration of our current agreements;

our ability to meet the financial covenants under our New Credit Facilities and other indebtedness;

expectations regarding maintenance and capital expenditures; and

the impact of legislative, regulatory, competitive and technological changes.

Such forward‑looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Quarterly Report on Form 10‑Q. Such forward‑looking statements are based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the projects will operate and perform in accordance with our expectations. Many of these risks and uncertainties can affect our actual results and could cause our actual results to differ materially from those expressed or implied in any forward‑looking statement made by us or on our behalf.

Forward‑looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. In addition, a number of factors could cause actual results to differ materially from the results discussed in the forward‑looking statements, including, but not limited to, the factors included in the filings Atlantic Power makes from time to time with the SEC and the risk factors described under “Item 1A. Risk Factors” in our Annual Report on Form 10‑K for the year ended December 31, 2015 and in this Quarterly Report on Form 10‑Q. To the extent any risk factors in our Annual Report on Form 10‑K for the year ended December 31, 2015 relate to the factual information disclosed elsewhere in this Quarterly Report on Form 10‑Q, including with respect to our business plan and any updates to our business strategy, such risk factors should be read in light of such information. Our business is both highly competitive and subject to various risks.

These risks include, without limitation:

our ability to service our debt obligations or generate sufficient cash flow to pay preferred dividends;

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our indebtedness and financing arrangements and the terms, covenants and restrictions included in our New Credit Facilities;

exchange rate fluctuations;

the impact of downgrades in our credit rating or the credit rating of our outstanding debt securities, and changes in our creditworthiness;

unstable capital and credit markets;

the expiration or termination of power purchase agreements and our ability to renew or enter into new power purchase agreements on favorable terms or at all;

the dependence of our projects on their electricity and thermal energy customers;

exposure of certain of our projects to fluctuations in the price of electricity or natural gas;

the dependence of our projects on third‑party suppliers;

projects not operating according to plan;

the effects of weather, which affects demand for electricity and fuel as well as operating conditions;

U.S., Canadian and/or global economic conditions and uncertainty;

risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war, natural disasters or other catastrophic events;

the adequacy of our insurance coverage;

the impact of significant energy, environmental and other regulations on our projects;

the impact of impairment of goodwill or long‑lived assets;

increased competition, including for acquisitions;

our limited control over the operation of certain minority‑owned projects;

transfer restrictions on our equity interests in certain projects;

risks inherent in the use of derivative instruments;

labor disruptions;

the impact of hostile cyber intrusions;

the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian Corruption of Foreign Public Officials Act;

our ability to retain, motivate and recruit executives and other key employees; and

our ability to remediate the reported material weakness in our internal control over financial reporting.

Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward‑looking information include third‑party projections of regional fuel and electric capacity and energy prices that are based on assumptions about future economic conditions and courses of action. Although the forward‑looking

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statements contained in this Quarterly Report on Form 10‑Q are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward‑looking statements, and the differences may be material. Certain statements included in this Quarterly Report on Form 10‑Q may be considered “financial outlook” for the purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10‑Q. These forward‑looking statements are made as of the date of this Quarterly Report on Form 10‑Q and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

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

The following discussion of the financial condition and results of operations of Atlantic Power should be read in conjunction with the interim consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10‑Q. All dollar amounts discussed below are in millions of U.S. dollars except per share amounts, or unless otherwise stated. The interim financial statements have been prepared in accordance with GAAP.

OVERVIEW

Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long‑term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of June 30, 2016, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in twenty‑three operational power generation projects across eleven states in the United States and two provinces in Canada. Eighteen of our projects are majority‑owned subsidiaries.

We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of utilities and other parties. Under the PPAs, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). Our PPAs have expiration dates ranging from December 31, 2017 to December 31, 2037, and approximately 25% of our PPAs on a MW‑weighted basis are scheduled to expire over the next four years. Our weighted average remaining PPA life is approximately 8 years. We also sell steam from a number of our projects to industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating.

The majority of our natural gas, coal and biomass power generation projects have long‑term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the term of the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass‑through of fuel costs to our customers. In cases where there is no pass‑through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of hedging strategies.

We directly operate and maintain eighteen of our power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

RECENT DEVELOPMENTS

Substantial Issuer Bid

On June 17, 2016, we commenced a substantial issuer bid to purchase for cancellation up to $65.0 million aggregate principal amount of our issued and outstanding 5.75% Series C Convertible Unsecured Subordinated Debentures maturing June 30, 2019. The offer expired on July 22, 2016. An aggregate of $62.7 million principal amount of the debentures were purchased and cancelled under the offer. As of August 4, 2016 there were approximately $42.6 million principal amount of Series C debentures outstanding. We will record a gain of approximately $1.3 million related to the repurchase in the consolidated statement of operations for the three and nine months ended September 30, 2016.

OUR POWER PROJECTS

The table below outlines our portfolio of power generating assets in operation as of August 4, 2016, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region. Our customers are generally large utilities and other parties with investment‑grade credit ratings, as measured by Standard & Poor’s (“S&P”). For customers rated by

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Moody’s, we substitute the corresponding S&P rating in the table below. Customers that have assigned ratings at the top end of the range of investment‑grade have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the lower end of the range of investment‑grade have weaker capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate the customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts or other obligations.

Customer

Power

Credit

Economic

Net

Contract

Rating

Project

Location

Type

Interest

Primary Electric Purchasers

Expiry

(S&P)

East U.S. Segment

Orlando(1)

Florida

Natural Gas

129

50.00

Progress Energy Florida

December, 2023

A–

Piedmont

Georgia

Biomass

100.00

Georgia Power

December, 2032

A–

Morris

Illinois

Natural Gas

177

100.00

120

Merchant

N/A

Equistar Chemicals, LP(2)

December, 2034

BBB+

Cadillac

Michigan

Biomass

100.00

Consumers Energy

December, 2028

BBB+

Chambers(1)

New Jersey

Coal

262

40.00

Atlantic City Electric(3)

March, 2024

BBB+

Chemours Co.

March, 2024

BB-

Kenilworth

New Jersey

Natural Gas

100.00

Merck & Co., Inc.

September, 2018

Curtis Palmer(4)

New York

Hydro

100.00

Niagara Mohawk Power Corporation

December, 2027

A–

Selkirk(1)

New York

Natural Gas

345

17.70

Merchant

N/A

West U.S. Segment

Naval Station

California

Natural Gas

100.00

San Diego Gas & Electric(5)

December, 2019

Naval Training Center

California

Natural Gas

100.00

San Diego Gas & Electric(5)

December, 2019

North Island

California

Natural Gas

100.00

San Diego Gas & Electric(5)

December, 2019

Oxnard

California

Natural Gas

100.00

Southern California Edison

May, 2020

BBB+

Manchief

Colorado

Natural Gas

300

100.00

300

Public Service Company of Colorado

April, 2022

A–

Frederickson(1)

Washington

Natural Gas

250

50.15

Benton Co. PUD

August, 2022

AA–

Grays Harbor PUD

August, 2022

A+

Franklin, Co. PUD

August, 2022

A+

Koma Kulshan(1)

Washington

Hydro

49.80

Puget Sound Energy

December, 2037

BBB

Canada Segment

Mamquam

British Columbia

Hydro

100.00

British Columbia Hydro and Power Authority

September, 2027

AAA

Moresby Lake

British Columbia

Hydro

100.00

British Columbia Hydro and Power Authority

August, 2022

AAA

Williams Lake

British Columbia

Biomass

100.00

British Columbia Hydro and Power Authority

March, 2018

AAA

Calstock

Ontario

Biomass

100.00

Independent Electricity System Operator

June, 2020

Kapuskasing

Ontario

Natural Gas

100.00

Independent Electricity System Operator

December, 2017

Nipigon

Ontario

Natural Gas

100.00

Independent Electricity System Operator

December, 2022

North Bay

Ontario

Natural Gas

100.00

Independent Electricity System Operator

December, 2017

Tunis(6)

Ontario

Natural Gas

100.00

Independent Electricity System Operator

⁽¹⁾

Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates.

⁽²⁾

Represents the credit rating of LyondellBasell, the parent company of Equistar Chemicals, as Equistar is not rated.

⁽³⁾

The base PPA with Atlantic City Electric (“ACE”) makes up the majority of the revenue from the 89 Net MW. For sales of energy and capacity not purchased by ACE under the base PPA and sold to the spot market, profits are shared with ACE under a separate power sales agreement.

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⁽⁴⁾

The Curtis Palmer PPA expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. From January 6, 1995 through June 30, 2016, the facility has generated 6,858 GWh under its PPA.

⁽⁵⁾

Our land leases with the U.S. Navy expire in February 2018 along with the associated energy sales agreements. We have initiated communications with the U.S. Navy to extend the leases through at least the expiration date of the PPAs in December 2019.

⁽⁶⁾

On January 20, 2015, we entered into an agreement with the Ontario Power Authority and its successor, the Independent Electricity System Operator (“IESO”), for the future operations of the Tunis facility. Subject to meeting certain technical modifications to the plant, gas delivery and other requirements, Tunis will operate under a 15‑year agreement with the IESO commencing between November 2017 and June 2019. The new contract will require the plant to become fully dispatchable as opposed to its current baseload configuration. As such, Tunis will provide electricity to the Ontario grid only when required, thereby assisting to reduce the incidents of surplus baseload generation in the market. The new agreement provides the Tunis project with a fixed monthly payment which escalates annually according to a pre‑defined formula while allowing it to earn additional energy revenues for those periods during which it is called upon to operate.

Consolidated Overview and Results of Operations

Performance highlights

The following table provides a summary of our consolidated results of operations for the three and six months ended June 30, 2016 and 2015, which are analyzed in greater detail below:


	Three months ended				Six months ended
	June 30,				June 30,
	2016		2015		2016		2015

Project revenue	$	98.2	$	103.1	$	204.6	$	214.4
Project income	$	25.2	$	17.2	$	53.9	$	38.8
(Loss) income from continuing operations	$	(16.3)	$	(20.0)	$	(29.3)	$	4.7
Income from discontinued operations	$	—	$	33.6	$	—	$	21.1
Net (loss) income attributable to Atlantic Power Corporation	$	(18.5)	$	14.7	$	(33.5)	$	32.2
Loss per share from continuing operations attributable to Atlantic Power Corporation—basic and diluted	$	(0.15)	$	(0.18)	$	(0.28)	$	—
Earnings per share from discontinued operations—basic and diluted		—		0.30		—		0.26
(Loss) earnings per share attributable to Atlantic Power Corporation—basic and diluted	$	(0.15)	$	0.12	$	(0.28)	$	0.26
Project Adjusted EBITDA(1)	$	46.2	$	43.9	$	108.7	$	102.5

⁽¹⁾

See reconciliation and definition in Supplementary Non‑GAAP Financial Information.

Revenue decreased from $103.1 million in the three months ended June 30, 2016 to $98.2 million, a decrease of $4.9 million from the comparable 2015 period. The primary drivers of the decrease are as follows:

Impact of lower fuel costs – energy revenue pricing at several of our projects is impacted by changes in fuel cost. Lower fuel prices during 2016 resulted in a $2.6 million decrease in revenue from 2015. These decreases in revenue are offset by lower fuel expense so the net impact on project income is not material;

Hydrological conditions – a $1.3 million decrease from lower water flows at our hydro projects; and

Currency – an approximate $1.8 million impact at our Canadian projects resulting from fluctuations of the Canadian Dollar against the U.S. dollar. The decrease in revenue due to currency is partially offset by the benefit of lower expenses also from currency at our Canadian projects. Currency had a net negative impact of $0.4 million on consolidated project income relative to the comparable 2015 period.

Consolidated project income was $25.2 million for the three months ended June 30, 2016, an increase of $8.0 million from the comparable 2015 period. The primary drivers of the increase are as follows:

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Fuel swap and natural gas purchases – Change in fair value of derivatives increased $5.4 million from the comparable 2015 period due to favorable future settlement gas prices, partially offset by negative change of $1.8 million from increased volume of interest swaps entered into for the New Term Loans.

Depreciation and amortization – depreciation and amortization decreased $2.7 million from the comparable 2015 period due to lower property, plant and equipment resulting from a $76.6 million long-lived asset impairment recorded in the fourth quarter of 2015.

These increases in project income were partially offset by decreases in project income resulting from:

Revenue – revenue decreased $4.9 million as discussed above.

Revenue decreased from $214.4 million in the six months ended June 30, 2016 to $204.6 million, a decrease of $9.8 million from the comparable 2015 period. The primary drivers of the decrease are as follows:

Impact of lower fuel costs – energy revenue pricing at several of our projects is impacted by changes in fuel cost. Lower fuel prices during 2016 resulted in an $11.7 million decrease in revenue from 2015. These decreases in revenue are offset by lower fuel expense so the net impact on project income is not material; and

Currency – an approximate $6.9 million impact at our Canadian projects resulting from fluctuations of the Canadian Dollar against the U.S. dollar. The decrease in revenue due to currency is partially offset by the benefit of lower expenses also from currency at our Canadian projects. Currency had a net negative impact of $2.1 million on consolidated project income relative to the comparable 2015 period.

These decreases were partially offset by:

Hydrological conditions – a $4.3 million increase from higher water flows at our hydro projects.

Consolidated project income was $53.9 million for the six months ended June 30, 2016, an increase of $15.1 million from the comparable 2015 period. The primary drivers of the increase are as follows:

Fuel expense – fuel expense decreased from $84.2 million in the six months ended June 30, 2015 to $74.0 million in the six months ended June 30, 2016 primarily due to lower natural gas prices; and

Depreciation and amortization – depreciation and amortization decreased $5.8 million from the comparable 2015 period due to lower property, plant and equipment resulting from a $76.6 million long-lived asset impairment recorded in the fourth quarter of 2015.

These increases in project income were partially offset by decreases in project income resulting from:

Revenue – revenue decreased $9.8 million as discussed above.

A detailed discussion of project income (loss) by segment is provided in Consolidated Overview and Results of Operations below. The discussion of Project Adjusted EBITDA by segment begins on page 51.

We have four reportable segments: East U.S., West U.S., Canada and Un‑Allocated Corporate. We revised our reportable business segments in the second quarter of 2015 as the result of recent significant asset sales and in order to align with changes in management’s structure, resource allocation and performance assessment in making decisions regarding our operations. The Wind Projects, which made up the entirety of the former Wind segment, were sold in June 2015 and are designated as discontinued operations for the three and six months ended June 30, 2015. The segment classified as Un‑allocated Corporate includes activities that support the executive and administrative offices, capital structure, costs of being a public registrant, costs to develop future projects and intercompany eliminations. These costs are not allocated to the operating segments when determining segment profit or loss. Project income (loss) is the primary GAAP measure of our operating results and is discussed below by reportable segment.

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Three months ended June 30, 2016 compared to the three months ended June 30, 2015

The following table provides our consolidated results of operations:


	Three months ended June 30,
	2016		2015		$ change		% change
Project revenue:
Energy sales	$	45.1	$	47.5	$	(2.4)	(5.1)	%
Energy capacity revenue		37.3		38.0		(0.7)	(1.8)	%
Other		15.8		17.6		(1.8)	(10.2)	%
		98.2		103.1		(4.9)	(4.8)	%
Project expenses:
Fuel		35.1		38.0		(2.9)	(7.6)	%
Operations and maintenance		30.0		35.3		(5.3)	(15.0)	%
Depreciation and amortization		25.5		28.2		(2.7)	(9.6)	%
		90.6		101.5		(10.9)	(10.7)	%
Project other income:
Change in fair value of derivative instruments		12.2		6.8		5.4	79.4	%
Equity in earnings of unconsolidated affiliates		7.6		8.6		(1.0)	(11.6)	%
Interest expense, net		(2.4)		(2.0)		(0.4)	20.0	%
Other income, net		0.2		2.2		(2.0)	(90.9)	%
		17.6		15.6		2.0	12.8	%
Project income		25.2		17.2		8.0	46.5	%
Administrative and other expenses (income):
Administration		5.8		6.6		(0.8)	(12.1)	%
Interest, net		51.2		24.6		26.6	108.1	%
Foreign exchange loss		2.6		4.8		(2.2)	(45.8)	%
Other expense (income), net		0.3		(1.7)		2.0	(117.6)	%
		59.9		34.3		25.6	74.6	%
Loss from continuing operations before income taxes		(34.7)		(17.1)		(17.6)	102.9	%
Income tax (benefit) expense		(18.4)		2.9		(21.3)	NM
Loss from continuing operations		(16.3)		(20.0)		3.7	(18.5)	%
Income from discontinued operations, net of tax		—		33.6		(33.6)	(100.0)	%
Net (loss) income		(16.3)		13.6		(29.9)	NM
Net loss attributable to noncontrolling interests		—		(3.4)		3.4	(100.0)	%
Net income attributable to Preferred share dividends of a subsidiary company		2.2		2.3		(0.1)	(4.3)	%
Net (loss) income attributable to Atlantic Power Corporation	$	(18.5)	$	14.7	$	(33.2)	NM

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	Three months ended June 30, 2016
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	17.5	$	7.6	$	20.0	$	—	$	45.1
Energy capacity revenue		13.0		13.3		11.0		—		37.3
Other		3.2		4.6		7.8		0.2		15.8
		33.7		25.5		38.8		0.2		98.2
Project expenses:
Fuel		12.0		7.9		15.2		—		35.1
Operations and maintenance		10.9		6.2		12.7		0.2		30.0
Depreciation and amortization		8.5		7.3		9.6		0.1		25.5
		31.4		21.4		37.5		0.3		90.6
Project other income (expense):
Change in fair value of derivative instruments		2.5		—		11.6		(1.9)		12.2
Equity in earnings of unconsolidated affiliates		7.1		0.5		—		—		7.6
Interest expense, net		(2.4)		—		—		—		(2.4)
Other expense, net		0.1		—		—		0.1		0.2
		7.3		0.5		11.6		(1.8)		17.6
Project income (loss)	$	9.6	$	4.6	$	12.9	$	(1.9)	$	25.2


	Three months ended June 30, 2015
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total (1)
Project revenue:
Energy sales	$	20.5	$	8.4	$	18.6	$	—	$	47.5
Energy capacity revenue		14.3		13.1		10.6		—		38.0
Other		4.1		4.8		8.5		0.2		17.6
		38.9		26.3		37.7		0.2		103.1
Project expenses:
Fuel		13.5		8.8		15.7		—		38.0
Operations and maintenance		9.4		14.9		10.4		0.6		35.3
Development		—		—		—		—		—
Depreciation and amortization		8.4		7.3		12.7		(0.2)		28.2
		31.3		31.0		38.8		0.4		101.5
Project other income (expense):
Change in fair value of derivative instruments		2.9		—		3.9		—		6.8
Equity in earnings of unconsolidated affiliates		8.2		0.4		—		—		8.6
Interest expense, net		(2.0)		—		—		—		(2.0)
Other expense, net		—		—		—		2.2		2.2
		9.1		0.4		3.9		2.2		15.6
Project income (loss)	$	16.7	$	(4.3)	$	2.8	$	2.0	$	17.2

⁽¹⁾

Excludes the Wind Projects, which were designated as discontinued operations for the three months ended June 30, 2015. The Wind Projects were sold in June 2015.

East U.S.

Project income for the three months ended June 30, 2016 decreased $7.1 million from the comparable 2015 period primarily due to:

decreased project income of $3.1 million at Curtis Palmer primarily due to lower water flow than the comparable period in 2015;

decreased project income of $2.9 million at Piedmont primarily due to a $2.1 million decrease in change in fair value of derivatives, a $0.4 million increase in interest expense and a $0.3 million decrease in energy sales; and

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decreased project income of $2.4 million at Morris primarily due to a $1.3 million decrease in capacity revenue from lower gas prices, a $0.7 million decrease in change in fair value of derivatives and a $0.3 million increase in depreciation.

These decreases were partially offset by:

Increased project income of $2.3 million at Orlando primarily due to a $2.4 million increase in change in fair value of derivatives.

West U.S.

Project income for the three months ended June 30, 2016 increased $8.9 million from the comparable 2015 period primarily due to:

increased project income of $8.3 million at Manchief primarily due to lower maintenance costs than the comparable period in 2015. Manchief underwent a scheduled maintenance overhaul outage during the second quarter of 2015.

Canada

Project income for the three months ended June 30, 2016 increased $10.1 million from the comparable 2015 period primarily due to:

increased project income of $2.8 million at Nipigon primarily due to a positive $3.0 million change in the fair value of gas purchase agreements that are accounted for as derivatives;

increased project income of $2.0 million at Williams Lake due to a $2.6 million decrease in depreciation expenses resulting from a long-lived asset impairment recorded in the fourth quarter of December 31, 2015, offset by lower energy revenue;

increased project income of $1.9 million at Mamquam primarily due to a $1.7 million increase in energy sales from higher water flow than the comparable period in 2015;

increased project income of $1.6 million at North Bay primarily due to a positive $2.4 million change in the fair value of gas purchase agreements that are accounted for as derivatives, offset by a $1.1 million increase in operations and maintenance cost; and

increased project income of $1.4 million at Kapuskasing primarily due to a positive $2.4 million change in the fair value of gas purchase agreements that are accounted for as derivatives, offset by a $1.1 million increase in operations and maintenance cost.

Un‑allocated Corporate

Total project loss for the three months ended June 30, 2016 increased by $3.9 million from the comparable 2015 period primarily due to a $2.3 million gain on sale of the Frontier solar development project in 2015 and a $1.9 million decrease in the fair value of interest rate swap agreements at APLP.

Administrative and other expenses (income)

Administrative and other expenses (income) include the income and expenses not attributable to any specific project and is allocated to the Un‑allocated Corporate segment. These costs include the activities that support the executive and administrative offices, treasury function, costs of being a public registrant, costs to develop or acquire future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate taxes. Significant non‑cash items that impact Administrative and other expenses (income), and that are subject to potentially significant fluctuations include the non‑cash impact of foreign exchange fluctuations from period to period on

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the U.S. dollar equivalent of our Canadian dollar‑denominated obligations and the related deferred income tax expense (benefit) associated with these non‑cash items.

Administration

Administration expense decreased $0.8 million or 12.1% from the comparable 2015 period primarily due to a $0.3 million decrease in compensation costs and a $0.3 million decrease in rent expense.

Interest, net

Interest expense increased $26.6 million or 108.1% from the comparable 2015 period primarily due to $31.4 million of deferred financing costs written off related to the Senior Secured Credit Facilities and repurchase and cancellation of convertible debentures. This was partially offset by lower interest expense related to the 9.0% Notes that were redeemed in July 2015.

Foreign exchange loss (gain)

Foreign exchange loss decreased $2.2 million, or 45.8%, from the comparable 2015 period primarily due to a $2.7 million decrease in unrealized loss in the revaluation of instruments denominated in Canadian dollars. The closing U.S. dollar to Canadian dollar exchange rates were 1.29 and 1.25 at June 30, 2016 and 2015, respectively, a decrease of 0.5% as compared to a decrease of 1.4% in 2015. The average U.S. dollar to Canadian dollar exchange rates were 1.29 and 1.25 for the three months ended June 30, 2016 and 2015, respectively.

Other expense, net

Other expense, net increased $2.0 million primarily due to a $1.7 million gain on repurchase of convertible debentures in the comparable 2015 period.

Income tax expense

Six months ended June 30, 2016 compared to the six months ended June 30, 2015

The following table provides our consolidated results of operations:

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	Six months ended June 30,
	2016		2015		$ change		% change
Project revenue:
Energy sales	$	97.6	$	101.5	$	(3.9)	(3.8)	%
Energy capacity revenue		69.2		71.5		(2.3)	(3.2)	%
Other		37.8		41.4		(3.6)	(8.7)	%
		204.6		214.4		(9.8)	(4.6)	%
Project expenses:
Fuel		74.0		84.2		(10.2)	(12.1)	%
Operations and maintenance		51.2		56.8		(5.6)	(9.9)	%
Development		—		1.1		(1.1)	(100.0)	%
Depreciation and amortization		50.3		56.1		(5.8)	(10.3)	%
		175.5		198.2		(22.7)	(11.5)	%
Project other income:
Change in fair value of derivative instruments		11.0		5.2		5.8	111.5	%
Equity in earnings of unconsolidated affiliates		18.3		19.3		(1.0)	(5.2)	%
Interest expense, net		(4.5)		(4.1)		(0.4)	9.8	%
Other income, net		—		2.2		(2.2)	(100.0)	%
		24.8		22.6		2.2	9.7	%
Project income		53.9		38.8		15.1	38.9	%
Administrative and other expenses (income):
Administration		11.9		16.0		(4.1)	(25.6)	%
Interest, net		67.8		50.3		17.5	34.8	%
Foreign exchange loss (gain)		22.5		(27.4)		49.9	NM
Other income, net		(2.2)		(3.1)		0.9	(29.0)	%
		100.0		35.8		64.2	179.3	%
(Loss) income from continuing operations before income taxes		(46.1)		3.0		(49.1)	NM
Income tax benefit		(16.8)		(1.7)		(15.1)	NM
Income (loss) from continuing operations		(29.3)		4.7		(34.0)	NM
Income from discontinued operations, net of tax		—		21.1		(21.1)	NM
Net (loss) income		(29.3)		25.8		(55.1)	NM
Net loss attributable to noncontrolling interests		—		(11.0)		11.0	(100.0)	%
Net income attributable to Preferred share dividends of a subsidiary company		4.2		4.6		(0.4)	(8.7)	%
Net (loss) income attributable to Atlantic Power Corporation	$	(33.5)	$	32.2	$	(65.7)	NM


	Six months ended June 30, 2016
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	39.9	$	14.0	$	43.7	$	—	$	97.6
Energy capacity revenue		24.8		19.9		24.5		—		69.2
Other		8.4		10.6		18.3		0.5		37.8
		73.1		44.5		86.5		0.5		204.6
Project expenses:
Fuel		25.7		15.9		32.4		—		74.0
Operations and maintenance		19.0		13.0		18.5		0.7		51.2
Depreciation and amortization		17.0		14.6		18.4		0.3		50.3
		61.7		43.5		69.3		1.0		175.5
Project other income (expense):
Change in fair value of derivative instruments		1.7		—		12.1		(2.8)		11.0
Equity in earnings of unconsolidated affiliates		17.0		1.3		—		—		18.3
Interest expense, net		(4.5)		—		—		—		(4.5)
Other expense, net		—		—		—		—		—
		14.2		1.3		12.1		(2.8)		24.8
Project income (loss)	$	25.6	$	2.3	$	29.3	$	(3.3)	$	53.9

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	Six months ended June 30, 2015
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total (1)
Project revenue:
Energy sales	$	40.0	$	18.8	$	42.7	$	—	$	101.5
Energy capacity revenue		26.3		19.8		25.4		—		71.5
Other		10.2		10.7		20.1		0.4		41.4
		76.5		49.3		88.2		0.4		214.4
Project expenses:
Fuel		29.9		19.5		34.8		—		84.2
Operations and maintenance		16.6		20.5		18.2		1.5		56.8
Development		—		—		—		1.1		1.1
Depreciation and amortization		16.4		14.5		24.8		0.4		56.1
		62.9		54.5		77.8		3.0		198.2
Project other income (expense):
Change in fair value of derivative instruments		0.4		—		5.6		(0.8)		5.2
Equity in earnings of unconsolidated affiliates		18.1		1.2		—		—		19.3
Interest expense, net		(4.1)		—		—		—		(4.1)
Other (expense) income, net		—		—		—		2.2		2.2
		14.4		1.2		5.6		1.4		22.6
Project income (loss)	$	28.0	$	(4.0)	$	16.0	$	(1.2)	$	38.8

⁽¹⁾

Excludes the Wind Projects, which were designated as discontinued operations for the three months ended June 30, 2015. The Wind Projects were sold in June 2015.

East U.S.

Project income for the six months ended June 30, 2016 decreased $2.4 million from the comparable 2015 period primarily due to:

decreased project income of $3.5 million at Piedmont primarily due to lower energy rates and higher fuel usage due to wet weather; and

decreased project income of $2.5 million at Morris primarily due to lower gas prices than the comparable period in 2015.

These decreases were partially offset by:

Increased project income of $4.6 million at Orlando primarily due to a $4.8 million increase in change in fair value of derivatives.

West U.S.

Project income for the six months ended June 30, 2016 increased $6.3 million from the comparable 2015 period primarily due to:

increased project income of $7.9 million at Manchief primarily due to a scheduled maintenance overhaul outage resulting in higher maintenance costs in the comparable period in 2015.

Canada

Project income for the six months ended June 30, 2016 increased $13.3 million from the comparable 2015 period primarily due to:

increased project income of $4.8 million at Williams Lake due to a $5.3 million decrease in depreciation expenses resulting from a long-lived asset impairment recorded in the fourth quarter of December 31, 2015;

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increased project income of $3.1 million at Mamquam primarily due to a $3.0 million increase in energy sales from higher water flows than the comparable period in 2015;

increased project income of $2.1 million at Nipigon primarily due to a positive $2.2 million change in the fair value of gas purchase agreements that are accounted for as derivatives;

increased project income of $1.7 million at North Bay primarily due to a positive $2.2 million change in the fair value of gas purchase agreements that are accounted for as derivatives; and

increased project income of $1.2 million at Kapuskasing primarily due to a positive $2.2 million change in the fair value of gas purchase agreements that are accounted for as derivatives, offset by a $1.0 million decrease in revenue due to a maintenance outage.

Un‑allocated Corporate

Total project loss for the six months ended June 30, 2016 decreased by $2.1 million from the comparable 2015 period primarily due to a $2.0 million decrease in the fair value of interest rate swap agreements at APLP.

Administrative and other expenses (income)

Administration

Administration expense decreased $4.1 million or 25.6% from the comparable 2015 period primarily due to a $2.0 million decrease in employee compensation expense, a $1.0 million decrease in professional services and a $1.1 million decrease in rent expense.

Interest, net

Interest expense increased $17.5 million or 34.8% from the comparable 2015 period primarily due to $31.4 million of deferred financing costs written off related to the Senior Secured Credit Facilities and repurchase and cancellation of convertible debentures. This was partially offset by lower interest expense related to the 9.0% Notes that were redeemed in July 2015.

Foreign exchange loss (gain)

Foreign exchange loss increased $49.9 million from the comparable 2015 period primarily due to a $50.1 million increase in unrealized loss in the revaluation of instruments denominated in Canadian dollars. The closing U.S. dollar to Canadian dollar exchange rates were 1.29 and 1.25 at June 30, 2016 and 2015, respectively, a decrease of 6.7% as compared to an increase of 7.7% in 2015. The average U.S. dollar to Canadian dollar exchange rates were 1.32 and 1.26 for the six months ended June 30, 2016 and 2015, respectively.

Income tax expense

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Project Operating Performance

Two of the primary metrics we utilize to measure the operating performance of our projects are generation and availability. Generation measures the net output of our proportionate project ownership percentage in megawatt hours. Availability is calculated by dividing the total scheduled hours of a project less forced outage hours by the total hours in the period measured. The terms of our PPAs require our projects to maintain certain levels of availability. The majority of our projects were able to achieve their respective capacity payments. For projects where reduced availability adversely impacted capacity payments, the impact was not material for the three and six months ended June 30, 2016. The terms of our PPAs provide for certain levels of planned and unplanned outages. All references below are denominated in thousands of Net MWh.


	Generation(1)
	Three months ended June 30,
			% change
(in thousands of Net MWh)	2016	2015	2016 vs. 2015
Segment
East U.S.	616.7	646.1	(4.6)	%
West U.S.	360.1	417.7	(13.8)	%
Canada	501.1	456.7	9.7	%
Total	1,477.9	1,520.5	(2.8)	%

⁽¹⁾

Excludes the Wind Projects, which were designated as discontinued operations for the three months ended June 30, 2015. The Wind Projects were sold in June 2015.

Three months ended June 30, 2016 compared with three months ended June 30, 2015

Aggregate power generation for the three months ended June 30, 2016 decreased 2.8% from the comparable 2015 period primarily due to:

decreased generation in the West U.S. segment primarily due to a 78.0 net MWh decrease in generation at Frederickson due to an outage in the second quarter of 2016, partially offset by a 14.0 net MWh increase in generation at Naval Training Center due to higher availability.

These decreases were partially offset by:

increased generation in the Canada segment was primarily due to a 50.1 net MWh increase in generation at Mamquam due to higher water flow, partially offset by a 6.2 MWh decrease in generation at Nipigon due to the maintenance outage.


	Generation(1)
	Six months ended June 30,
			% change
(in thousands of Net MWh)	2016	2015	2016 vs. 2015
Segment
East U.S.	1,283.6	1,299.4	(1.2)	%
West U.S.	702.7	767.4	(8.4)	%
Canada	1,044.9	973.7	7.3	%
Total	3,031.2	3,040.5	(0.3)	%

⁽¹⁾

Excludes the Wind Projects, which were designated discontinued operations for the three and six months ended June 30, 2015. The Wind Projects were sold in June 2015.

Six months ended June 30, 2016 compared with six months ended June 30, 2015

Aggregate power generation for the six months ended June 30, 2016 decreased 0.3% from the comparable 2015 period primarily due to:

decreased generation in the West U.S. segment primarily due to a 76.7 net MWh decrease in generation at

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Manchief due to lower dispatch and a 10.8 MWh decrease in generation at North Island due to the maintenance outage, partially offset by a 16.8 MWh increase in generation at Frederickson due to an outage in the second quarter of 2016.

This decrease was partially offset by:

increased generation in the Canada segment primarily due to a 71.4 net MWh increase in generation at Mamquam due to higher water flows; and

increased generation in the East U.S. segment primarily due to a 34.3 net MWh increase in generation at Morris due to higher demand and lower gas prices and a 20.8 MWh increase in generation at Curtis Palmer due to higher water flow, partially offset by a 15.7 MWh decrease in generation at Selkirk due to lower demand.


	Availability(1)
	Three months ended
	June 30,
					% change
	2016		2015		2016 vs. 2015
Segment
East U.S.	92.7	%	94.5	%	(1.9)	%
West U.S.	90.6	%	81.8	%	10.8	%
Canada	95.1	%	94.1	%	1.1	%
Weighted average	92.7	%	91.0	%	1.9	%

⁽¹⁾

Excludes the Wind Projects, which were designated as discontinued operations for the three months ended June 30, 2015. The Wind Projects were sold in June 2015.

Three months ended June 30, 2016 compared with three months ended June 30, 2015

Weighted average availability for the three months ended June 30, 2016 increased 1.9% from the comparable 2015 period primarily due to:

increased availability in the West U.S. segment primarily due to Manchief and Naval Training Center, which underwent maintenance outages in the comparable 2015 period; and

increased availability in the Canada segment primarily due to Calstock, which underwent an outage during the comparable period in 2015.

These increases were partially offset by:

decreased availability in the East U.S. segment primarily due to Selkirk, which underwent an extended scheduled maintenance outage from March 2016.


	Availability(1)
	Six months ended
	June 30,
					% change
	2016		2015		2016 vs. 2015
Segment
East U.S.	95.9	%	96.2	%	(0.3)	%
West U.S.	90.1	%	89.5	%	0.7	%
Canada	97.3	%	95.5	%	1.9	%
Weighted average	94.6	%	94.2	%	0.4	%

⁽²⁾

Excludes the Wind Projects, which were designated as discontinued operations for the three and six months ended June 30, 2015. The Wind Projects were sold in June 2015.

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Six months ended June 30, 2016 compared with six months ended June 30, 2015

Weighted average availability for the six months ended June 30, 2016 increased 0.4% from the comparable 2015 period primarily due to:

increased availability in the Canada segment primarily due to Mamquam, which underwent an outage during the comparable period in 2015.

Supplementary Non‑GAAP Financial Information

The key measurement we use to evaluate the results of our business is Project Adjusted EBITDA. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non‑cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We believe that Project Adjusted EBITDA is a useful measure of financial results at our projects because it excludes non-cash impairment charges, gains or losses on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project Adjusted EBITDA is Project income. A reconciliation of Net (loss) income to Project income and to Project Adjusted EBITDA is provided under “Project Adjusted EBITDA” below. Project Adjusted EBITDA for our equity investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below.

Project Adjusted EBITDA



	Three months ended						Six months ended
	June 30,				$ change		June 30,				$ change
	2016		2015		2016 vs 2015		2016		2015		2016 vs 2015
Net (loss) income	$	(16.3)	$	13.6	$	(29.9)	$	(29.3)	$	25.8	$	(55.1)
Net Income from discontinued operations, net of tax		-		33.6		(33.6)		—		21.1		(21.1)
Income tax (benefit) expense		(18.4)		2.9		(21.3)		(16.8)		(1.7)		(15.1)
(Loss) income from continuing operations before income taxes		(34.7)		(17.1)		(17.6)		(46.1)		3.0		(49.1)
Administration		5.8		6.6		(0.8)		11.9		16.0		(4.1)
Interest, net		51.2		24.6		26.6		67.8		50.3		17.5
Foreign exchange loss (gain)		2.6		4.8		(2.2)		22.5		(27.4)		49.9
Other income, net		0.3		(1.7)		2.0		(2.2)		(3.1)		0.9
Project income	$	25.2	$	17.2	$	8.0	$	53.9	$	38.8	$	15.1
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization		30.4		33.3		(2.9)		60.3		66.1		(5.8)
Interest expense, net		2.9		2.5		0.4		5.4		4.9		0.5
Change in the fair value of derivative instruments		(12.2)		(6.9)		(5.3)		(11.0)		(5.1)		(5.9)
Impairment and other expense		(0.1)		(2.2)		2.1		0.1		(2.2)		2.3
Project Adjusted EBITDA	$	46.2	$	43.9	$	2.3	$	108.7	$	102.5	$	6.2
Project Adjusted EBITDA by segment(1)
East U.S.		20.9		27.0		(6.1)		51.2		53.7		(2.5)
West U.S.		14.5		5.7		8.8		22.0		15.6		6.4
Canada		10.9		11.6		(0.7)		35.7		35.4		0.3
Un-Allocated Corporate		(0.1)		(0.4)		0.3		(0.2)		(2.2)		2.0
Total		46.2		43.9		2.3		108.7		102.5		6.2

⁽¹⁾

Excludes the Wind Projects, which were designated a component of discontinued operations for the three and six months ended June 30, 2015. The Wind Projects were sold in June 2015.

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East U.S.

The following table summarizes Project Adjusted EBITDA for our East U.S. segment for the periods indicated:


	Three months ended June 30,
					% change
	2016		2015		2016 vs. 2015
East U.S.
Project Adjusted EBITDA	$	20.9	$	27.0	(23)	%

Three months ended June 30, 2016 compared with three months ended June 30, 2015

Project Adjusted EBITDA for the three months ended June 30, 2016 decreased $6.1 million from the comparable 2015 period primarily due to decreased Project Adjusted EBITDA of:

$3.1 million at Curtis Palmer due to lower water flows than the comparable 2015 period;

$1.4 million at Morris due to lower fuel optimization from mild weather and increased maintenance expense than the comparable 2015 period; and

$0.6 million at Chambers due to lower energy and steam revenues resulting from decreased dispatch than in the comparable 2015 period.


	Six months ended June 30,
					% change
	2016		2015		2016 vs. 2015
East U.S.
Project Adjusted EBITDA	$	51.2	$	53.7	(5)	%

Six months ended June 30, 2016 compared with six months ended June 30, 2015

Project Adjusted EBITDA for the six months ended June 30, 2016 decreased $2.5 million from the comparable 2015 period primarily due to decreased Project Adjusted EBITDA of:

$1.4 million at Kenilworth due to the maintenance outage in May 2016;

$0.9 million at Morris due to lower gas prices than the comparable 2015 period;

$0.7 million at Chambers due to lower energy and steam revenues resulting from decreased dispatch than the comparable 2015 period; and

$0.7 million at Selkirk due to lower merchant revenues due to lower capacity, offset by lower fuel costs.

These decreases were partially offset by an increase in Project Adjusted EBITDA of:

$2.0 million at Curtis Palmer due to higher water flow than the comparable 2015 period.

West U.S.

The following table summarizes Project Adjusted EBITDA for our West U.S. segment for the periods indicated:


	Three months ended June 30,
					% change
	2016		2015		2016 vs 2015
West U.S.
Project Adjusted EBITDA	$	14.5	$	5.7	154	%

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Three months ended June 30, 2016 compared with three months ended June 30, 2015

Project Adjusted EBITDA for the three months ended June 30, 2016 increased $8.8 million from the comparable 2015 period primarily due to increased Project Adjusted EBITDA of:

$8.3 million at Manchief due to lower maintenance expense. Manchief underwent a maintenance overhaul in the comparable 2015 period.


	Six months ended June 30,
					% change
	2016		2015		2016 vs 2015
West U.S.
Project Adjusted EBITDA	$	22.0	$	15.6	41	%

Six months ended June 30, 2016 compared with six months ended June 30, 2015

Project Adjusted EBITDA for the six months ended June 30, 2016 increased $6.4 million from the comparable 2015 period primarily due to increased Project Adjusted EBITDA of:

$7.9 million at Manchief due to lower maintenance expense. Manchief underwent a maintenance overhaul in the comparable 2015 period.

This increase was partially offset by a decrease in Project Adjusted EBITDA of:

$0.9 million at Naval Station due to $0.9 million of higher maintenance expense related to a hot gas path maintenance outage.

Canada

The following table summarizes Project Adjusted EBITDA for our Canada segment for the periods indicated:


	Three months ended June 30,
					% change
	2016		2015		2016 vs. 2015
Canada
Project Adjusted EBITDA	$	10.9	$	11.6	(6)	%

Three months ended June 30, 2016 compared with three months ended June 30, 2015

Project Adjusted EBITDA for the three months ended June 30, 2016 decreased $0.7 million from the comparable 2015 period primarily due to decreases in Project Adjusted EBITDA of:

$1.1 million at Kapuskasing due to a maintenance outage in June 2016;

$0.9 million at North Bay due to a maintenance outage in June 2016; and

$0.6 million at William Lake due to lower energy revenue.

These decreases were partially offset by an increase in Project Adjusted EBITDA of:

$2.0 million at Mamquam due to higher water flows than the comparable 2015 period.

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	Six months ended June 30,
					% change
	2016		2015		2016 vs. 2015
Canada
Project Adjusted EBITDA	$	35.7	$	35.4	1	%

Six months ended June 30, 2016 compared with six months ended June 30, 2015

Project Adjusted EBITDA for the six months ended June 30, 2016 increased $0.3 million from the comparable 2015 period primarily due to an increase in Project Adjusted EBITDA of:

$3.1 million at Mamquam due to higher water flow than the comparable 2015 period.

This increase was partially offset by decreases in Project Adjusted EBITDA of:

$1.4 million at Kapuskasing due to a maintenance outage in June 2016;

$0.8 million at North Bay due to a maintenance outage in June 2016; and

$0.6 million at William Lake due to lower energy revenue.

Un‑allocated Corporate

The following table summarizes Project Adjusted EBITDA for our Un‑allocated Corporate segment for the periods indicated:


	Three months ended June 30,
					% change
	2016		2015		2016 vs. 2015
Un-allocated Corporate
Project Adjusted EBITDA	$	(0.1)	$	(0.4)	(75)	%

Three months ended June 30, 2016 compared with three months ended June 30, 2015

Project Adjusted EBITDA for the three months ended June 30, 2016 did not change materially.


	Six months ended June 30,
					% change
	2016		2015		2016 vs. 2015
Un-allocated Corporate
Project Adjusted EBITDA	$	(0.2)	$	(2.2)	(91)	%

Six months ended June 30, 2016 compared with six months ended June 30, 2015

Project Adjusted EBITDA for the six months ended June 30, 2016 increased $2.0 million from the comparable 2015 period primarily due to an increase in Project Adjusted EBITDA of:

$0.9 million of lower compensation expense from headcount reductions and $1.0 million in decreased development and administrative costs.

Project Adjusted EBITDA excludes the Wind Projects, which are designated as discontinued operations for the three and six months ended June 30, 2015. Project Adjusted EBITDA for the Wind Projects was $14.8 million and $28.1 million for the three and six months ended June 30, 2015, respectively.

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Liquidity and Capital Resources


	June 30,		December 31,
	2016		2015
Cash and cash equivalents	$	154.2	$	72.4
Restricted cash		14.3		15.2
Total		168.5		87.6
Revolving credit facility availability		97.2		106.0
Total liquidity	$	265.7	$	193.6

Overview

Our primary source of liquidity is distributions from our projects and availability under our revolving credit facility. Our future liquidity depends in part on our ability to successfully enter into new PPAs at projects when PPAs expire or terminate. PPAs in our portfolio have expiration dates ranging from December 31, 2017 (at our North Bay and Kapuskasing projects) to December 2037. We are currently in negotiations with counterparties regarding the renewal or entry into new power purchase agreements or may elect to operate certain facilities in the merchant market upon expiration of their PPAs. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA, if at all, or the price received by the project for power under subsequent arrangements may be reduced significantly. As a result, this may reduce the cash received from project distributions and the cash available for further debt reduction, identification of and investment in accretive growth opportunities (both internal and external), to the extent available, repurchase of common shares and other allocation of available cash. See “Risk Factors—Risks Related to Our Structure—We may not generate sufficient cash flow to pay dividends, if and when declared by our board of directors, service our debt obligations or finance internal or external growth opportunities or fund our operations” in our Annual Report on Form 10‑K for the year ended December 31, 2015.

We expect to reinvest approximately $53.2 million in our portfolio in the form of project capital expenditures and maintenance expenses in 2016. Such investments are generally paid at the project level. See “—Capital and Major Maintenance Expenditures” in our Annual Report on Form 10‑K for the year ended December 31, 2015. We do not expect any other material or unusual requirements for cash outflows for 2016 for capital expenditures or other required investments. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months.

Consolidated Cash Flow Discussion

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


	Six months ended
	June 30,
	2016		2015		Change
Net cash provided by operating activities	$	53.7	$	53.4	$	0.3
Net cash provided by investing activities		3.6		324.8		(321.2)
Net cash provided (used) in financing activities		24.5		(94.4)		118.9

Operating Activities

Cash flow from our projects may vary from period to period based on working capital requirements and the operating performance of the projects, as well as changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, and the transition to merchant or re‑contracted pricing following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

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For the six months ended June 30, 2016, the net increase in cash flows from operating activities of $0.3 million was primarily the result of the following:

Increase in Project Adjusted EBITDA – Project Adjusted EBITDA increased by $6.2 million primarily due to lower maintenance expense than the comparable 2015 period; and

Decrease in interest payments – We made $11.6 million in lower interest payments than the comparable 2015 period primarily due to the redemption of the 9.0% High Yield Notes in July 2015.

This increase was partially offset by a decrease in net cash provided by operating activities primarily the result of the following:

Sale of Wind Projects – in the first quarter of 2015, the Wind Projects, which were sold in June 2015, provided $21.9 million of operating cash flows.

Investing Activities

Cash flow from investing activities includes changes in restricted cash. Restricted cash fluctuates from period to period in part because certain of our non‑recourse project‑level financing arrangements require all operating cash flow from the project to be deposited in restricted accounts and then released at the time that principal payments are made and project‑level debt service coverage ratios are met. As a result, the timing of principal payments on certain of our project‑level debt causes significant fluctuations in restricted cash balances, which typically benefits investing cash flow in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year. For the six months ended June 30, 2016, the net decrease in cash flows from investing activities of $321.2 million was primarily the result of the following:

Sale of Wind Projects – we received $326.3 million of net proceeds from the sale of Wind Projects and the Frontier solar development project in the second quarter of 2015.

This decrease was partially offset by an increase in net cash provided by investing activities primarily the result of the following:

Reimbursement of construction cost – we received a reimbursement of $4.7 million for the construction project at Morris.

Financing Activities

For the six months ended June 30, 2016, the net increase in cash flows used in financing activities of $118.9 million was primarily the result of the following:

The New Credit Facilities – we received $679.0 million of net proceeds from issuance of the New Credit Facilities.

This increase was partially offset by decreases in net cash used by financing activities primarily as a result of the following:

Corporate and project-level debt – we redeemed the Senior Secured Credit Facilities in full for $447.9 million in the second quarter of 2016 and made $54.8 million of principal payments on our corporate and project-level debt; and

Convertible debenture repayments – we redeemed and cancelled Series A and B convertible debentures, in full, with a payment of $110.7 million with a portion of the proceeds from the New Credit Facilities and also redeemed and cancelled $16.2 million of convertibles debentures under the NCIB during 2016.

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Corporate Debt

The following table summarizes the maturities of our corporate debt at June 30, 2016:


							Remaining
	Maturity	Interest					Principal
	Date	Rates					Repayments		2016		2017		2018		2019		2020		Thereafter
Senior Secured Term Loan Facility(1)(2)	April 2023	6.00	%	-	6.30	%	$	674.9	$	35.0	$	100.0	$	90.0	$	65.0	$	105.0	$	279.9
Atlantic Power Income LP Note	June 2036	5.95	%					162.6		—		—		—		—		—		162.6
Convertible Debenture(3)	June 2019	5.75	%					105.3		—		—		—		105.3		—		—
Convertible Debenture	December 2019	6.00	%					62.7		—		—		—		62.7		—		—
Total Corporate Debt							$	1,005.5	$	35.0	$	100.0	$	90.0	$	233.0	$	105.0	$	442.5

⁽¹⁾

In addition to the annual principal payments described herein, the Credit Agreement requires payment of 50% of the excess cash flow of APLP Holdings LP and its subsidiaries. We entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $444.4 million of the $674.9 million outstanding aggregate borrowings at June 30, 2016. See Note 8, Accounting for derivative instruments and hedging activities for further details. The range of interest rates for the Senior Secured Term Loan Facility is based on LIBOR as of June 30, 2016.

⁽²⁾

The New Credit Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the New Credit Facilities and the MTNs, funding of the debt service reserve account, debt service on other permitted debt of APLP Holdings and its subsidiaries, capital expenditures permitted under the Credit Agreement, and payment on the preferred equity issued by Atlantic Power Preferred Equity Ltd., a subsidiary of APLP Holdings or (ii) such other amount up to 100% of the cash flow described in clause (i) above that is required to reduce the aggregate principal amount of New Term Loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule.

⁽³⁾

In July 2016, we purchased and cancelled $62.7 million principal amount of the debentures.

Project‑Level Debt

Project‑level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project‑level debt generally amortizes during the term of the respective revenue‑generating contracts of the projects. All project‑level debt is non‑recourse to us and substantially the entire principal is amortized over the life of the projects’ PPAs. The following table summarizes the maturities of project‑level debt. The amounts represent our share of the non‑recourse project‑level debt balances at June 30, 2016. Certain of the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project‑level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. At August 4, 2016, all of our projects with the exception of Piedmont were in compliance with the covenants contained in project‑level debt. Projects that do not meet their debt service coverage ratios are limited from making distributions, but are not callable or subject to acceleration under the terms of their debt agreements. We do not expect our Piedmont project to meet its debt service coverage ratio covenants or to make distributions before the project’s debt maturity in 2018 at the earliest. See Note 5 to the consolidated financial statements of this Quarterly Report on Form 10-Q, Long‑term debt—Non‑Recourse Debt.

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The range of interest rates presented represents the rates in effect at June 30, 2016. The amounts listed below are in millions of U.S. dollars, except as otherwise stated.


							Total
							Remaining
	Maturity	Range of					Principal
	Date	Interest Rates					Repayments		2016		2017		2018		2019		2020		Thereafter
Consolidated Projects:
Epsilon Power Partners	January 2019	3.40	%				$	16.5	$	3.0	$	6.3	$	6.5	$	0.7	$	—	$	—
Piedmont	August 2018	8.47	%					59.0		2.4		2.5		54.1		—		—		—
Cadillac	August 2025	6.19	%					28.3		1.3		3.0		3.0		3.1		2.7		15.2
Total Consolidated Projects								103.8		6.7		11.8		63.6		3.8		2.7		15.2
Equity Method Projects:
Chambers(1)	December 2019 and 2023	4.50	%	-	5.00	%		42.9				—		—		5.2		7.8		29.9
Total Equity Method Projects								42.9		—		—		—		5.2		7.8		29.9
Total Project-Level Debt							$	146.7	$	6.7	$	11.8	$	63.6	$	9.0	$	10.5	$	45.1

⁽¹⁾

In June 2014, Chambers refinanced its project debt and issued (i) Series A (tax exempt) Bonds due December 2023, of which our proportionate share is $41.3 million and (ii) Series B (taxable) Bonds due December 2019, of which our proportionate share is $1.6 million. The above table does not include our $4.2 million proportionate share of issuance premiums.

Uses of Liquidity

Our requirements for liquidity and capital resources, other than operating our projects, consist primarily of principal and interest on our outstanding convertible debentures, senior notes and other corporate and project level debt, funding the repurchase of shares of our common stock (to the extent we choose to pursue any such repurchase), collateral and capital expenditures, including major maintenance and business development costs and dividend payments, if and when declared by our board of directors, to our common shareholders and preferred shareholders of a subsidiary company. We may fund future acquisitions with a combination of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately placed bank or institutional non‑recourse operating level debt, although we can provide no assurances regarding the availability of public or private financing on acceptable terms or at all.

Capital and Maintenance Expenditures

Capital expenditures and maintenance expenses for the projects are generally paid at the project level using project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures needed at the projects. The operating projects which we own consist of large capital assets that have established commercial operations. On‑going capital expenditures for assets of this nature are generally not significant because most expenditures relate to planned repairs and maintenance and are expensed when incurred.

We expect to reinvest approximately $8.4 million in 2016 (of which $2.0 million was reinvested in the six months ended June 30, 2016) in our portfolio in the form of project capital expenditures and incur $44.8 million of maintenance expenses (of which $23.3 million was incurred in the six months ended June 30, 2016). Such investments are generally paid at the project level. See “—Capital and Major Maintenance Expenditures” in our Annual Report on Form 10‑K for the year ended December 31, 2015. We do not expect any other material or unusual requirements for cash outflows for 2016 for capital expenditures or other required investments. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months.

We believe one of the benefits of our diverse fleet is that plant overhauls and other expenditures do not occur in the same year for each facility. Recognized industry guidelines and original equipment manufacturer recommendations provide a source of data to assess maintenance needs. In addition, we utilize predictive and risk‑based analysis to refine our expectations, prioritize our spending and balance the funding requirements necessary for these expenditures over time. Future capital expenditures and maintenance expenses may exceed the projected level in 2016 as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades.

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Scheduled maintenance outages during the six months ended June 30, 2016 occurred at such times that did not materially impact the facilities’ availability requirements under their respective PPAs.

Recently Adopted and Recently Issued Accounting Guidance

See Note 1 to the consolidated financial statements in this Quarterly Report on Form 10‑Q.

Off‑Balance Sheet Arrangements

As of June 30, 2016, we had no off‑balance sheet arrangements as defined in Item 303(a)(4) of Regulation S‑K.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to financial market risk results primarily from fluctuations in interest and currency rates and fuel and electricity prices. There have been no material changes to our market risks as disclosed in our Annual Report on Form 10‑K for the fiscal year ended December 31, 2015.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures, as defined in Rules 13a‑15(e) and 15d‑15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective as of June 30, 2016 as a result of the material weakness that exists in our internal control over financial reporting as previously described in our Annual Report on Form 10-K for the year ended December 31, 2015.

Previously Identified Material Weakness

As of December 31, 2015, Management concluded that our internal control over financial reporting was not effective due to the material weakness identified. Management concluded that the long-lived asset and goodwill impairment tests were not designed effectively to ensure the proper application of U.S. GAAP over (i) the determination of the carrying value of our asset groups and reporting units used in the accounting for long-lived asset recoverability and goodwill impairment test, and (ii) the determination of the long-lived asset and goodwill impairment charges. Specifically, with respect to (i) and (ii), we did not design and maintain effective controls related to determining the carrying value of the asset groups for the purpose of performing the long-lived asset impairment testing as we did not appropriately include the carrying value of goodwill in certain long-lived asset groups in which the asset group is at the same level as the reporting unit. This resulted in an initial conclusion that no long-lived asset impairment should be recorded and also impacted the carrying value of our reporting units for step 1 and step 2 of our goodwill impairment tests. These control deficiencies resulted in misstatements related to goodwill, property, plant and equipment, deferred income taxes and impairment, within the preliminary consolidated financial statements that were corrected prior to the issuance of the Company’s consolidated financial statements as of and for the fiscal year ended December 31, 2015.

A material weakness is defined as a deficiency, or combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected in a timely manner.

Management’s Remediation Plan

Management is actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness identified above. Management intends to take the following actions to address the material weakness:

Re-designing its controls, including the implementation of new controls, relating to the long-lived asset and goodwill impairment analysis, including: (i) enhancing the design and documentation of management review controls in order to enhance the precision at which management review controls operate, (ii) improving the documentation of

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internal control procedures, and (iii) enhancing the evaluation of the components of carrying value and comparison to the requirements of generally accepted accounting principles.

We are in the process of implementing our remediation plan and expect to have the material weakness remediated prior to December 31, 2016.

Changes in Internal Control over Financial Reporting

Other than the material weakness described above, there has been no change in our internal control over financial reporting during the three and six months ended June 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations of Disclosure Controls and Internal Control over Financial Reporting

Because of their inherent limitations, our disclosure controls and procedures and our internal control over financial reporting may not prevent material errors or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to risks, including that the control may become inadequate because of changes in conditions or that the degree of compliance with our policies or procedures may deteriorate.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are party to legal proceedings, including securities class actions, from time to time. In particular, we and/or certain of our current and former officers have been named as defendants in various class action lawsuits. Due to the nature of these proceedings, the lack of precise damage claims and the type of claims we are subject to, we are unable to determine the ultimate or maximum amount of monetary liability or financial impact, if any, to us in these legal matters, which unless otherwise specified, seek damages from the defendants of material or indeterminate amounts.

Shareholder class action lawsuits

The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015.

The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal.

The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs.

Other than as described above, there were no material changes to legal proceedings disclosed in “Item 3. Legal Proceedings” of our Annual Report on Form 10‑K for the year ended December 31, 2015.

ITEM 1A. RISK FACTORS

There were no material changes to the risk factors disclosed in “Item 1A. Risk Factors” of our Annual Report on Form 10‑K for the year ended December 31, 2015 (except to the extent additional factual information disclosed elsewhere in this Quarterly Report on Form 10‑Q relates to such risk factors (including, without limitation, the matters discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations”). To the extent any risk factors in our Annual Report on Form 10‑K for the year ended December 31, 2015 relate to the factual information disclosed elsewhere in this Quarterly Report on Form 10‑Q, including with respect to our business plan and any updated to our business strategy, such risk factors should be read in light of such information.

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ITEM 6. EXHIBITS

EXHIBIT INDEX


Exhibit No.		Description
10.1		Credit and Guaranty Agreement, dated as of April 13, 2016, among APLP Holdings Limited Partnership, as Borrower, Atlantic Power Corporation, as guarantor, Certain Subsidiaries of APLP Holdings Limited Partnership, as Guarantors, Various Lenders, Goldman Sachs Bank USA and Bank of America, N.A., as L/C Issuers, Goldman Sachs Lending Partners LLC and Bank of America, N.A., as Joint Syndication Agents, Goldman Sachs Lending Partners LLC as Administrative Agent and Collateral Agent, and Goldman Sachs Lending Partners LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Securities, LLC, and Industrial and Commercial Bank of China, in their respective capacities as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8‑K filed on April 13, 2016).
10.2		Securities Pledge Agreement, dated as of April 13, 2016, among Atlantic Power Corporation, Atlantic Power GP II, Inc. and Goldman Sachs Lending Partners LLC as Collateral Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8‑K filed on April 13, 2016).
31.1*		Certification of Chief Executive Officer pursuant to Rule 13a‑14(a) or Rule 15d‑14(a) of the Securities Exchange Act of 1934
31.2*		Certification of Chief Financial Officer pursuant to Rule 13a‑14(a) or Rule 15d‑14(a) of the Securities Exchange Act of 1934
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase
101.DEF*		XBRL Taxonomy Extension Definition Linkbase
101.LAB*		XBRL Taxonomy Extension Label Linkbase
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase

*Filed herewith.

**Furnished herewith.

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SIGNATURES

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


Date: August 8, 2016	Atlantic Power Corporation


	By:	/s/ Terrence Ronan
		Name:	Terrence Ronan
		Title:	Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)