ATLANTIC POWER CORP (Form: 10-Q, Received: 11/09/2017 17:13:55)

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 September 30, 2017
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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b‑2 of the Exchange Act. (Check one):


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

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

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

The number of shares outstanding of the registrant’s Common Stock as of November 7, 2017 was 115,211,976.

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ATLANTIC POWER CORPORATION

FORM 10‑Q

NINE MONTHS ENDED SEPTEMBER 30, 2017

Index

	General :		3
		PART I—FINANCIAL INFORMATION
ITEM 1.		CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
		Consolidated Balance Sheets as of September 30, 2017 (unaudited) and December 31, 2016	4
		Consolidated Statements of Operations for the three and nine months ended September 30, 2017 (unaudited) and September 30, 2016 (unaudited)	5
		Consolidated Statements of Comprehensive Loss for the three and nine months ended September 30, 2017 (unaudited) and September 30, 2016 (unaudited)	6
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 (unaudited) and September 30, 2016 (unaudited)	7
		Condensed Notes to Consolidated Financial Statements (unaudited)	8
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
ITEM 4.		CONTROLS AND PROCEDURES	57
		PART II—OTHER INFORMATION
ITEM 1A.		RISK FACTORS	59
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
ITEM 6.		EXHIBITS	61

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GENERAL

In this Quarterly Report on Form 10‑Q, references to “Cdn$” and “Canadian dollars” are to the lawful currency of Canada and references to “$”, “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)


	September 30,		December 31,
	2017		2016
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	122.4	$	85.6
Restricted cash		12.5		13.3
Accounts receivable		48.8		37.3
Current portion of derivative instruments asset (Notes 6 and 7)		2.5		4.0
Inventory		20.3		16.0
Prepayments		6.7		5.9
Income taxes receivable		0.5		—
Other current assets		3.9		2.8
Total current assets		217.6		164.9
Property, plant, and equipment, net (Note 4)		652.6		733.2
Equity investments in unconsolidated affiliates (Note 3)		199.8		266.8
Power purchase agreements and intangible assets, net (Note 4)		201.6		246.2
Goodwill (Note 4)		36.0		36.0
Derivative instruments asset (Notes 6 and 7)		2.6		4.6
Other assets		3.7		5.1
Total assets	$	1,313.9	$	1,456.8
Liabilities
Current liabilities:
Accounts payable	$	3.2	$	4.5
Accrued interest		4.5		0.7
Other accrued liabilities		23.0		24.4
Current portion of long-term debt (Note 5)		156.5		111.9
Current portion of derivative instruments liability (Notes 6 and 7)		13.5		7.6
Other current liabilities		2.6		1.8
Total current liabilities		203.3		150.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 5)		637.3		749.2
Convertible debentures, net of unamortized deferred financing costs		105.5		100.4
Derivative instruments liability (Notes 6 and 7)		19.5		21.3
Deferred income taxes		26.5		68.3
Power purchase and fuel supply agreement liabilities, net		24.7		25.3
Asset retirement obligations, net		52.7		50.2
Other long-term liabilities		4.5		5.3
Total liabilities		1,074.0		1,170.9
Equity
Common shares, no par value, unlimited authorized shares; 115,211,976 and 114,649,888 issued and outstanding at September 30, 2017 and December 31, 2016		1,274.3		1,272.9
Accumulated other comprehensive loss (Note 2)		(132.3)		(148.5)
Retained deficit		(1,117.3)		(1,059.8)
Total Atlantic Power Corporation shareholders’ equity		24.7		64.6
Preferred shares issued by a subsidiary company (Note 11)		215.2		221.3
Total equity		239.9		285.9
Total liabilities and equity	$	1,313.9	$	1,456.8

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Project revenue:
Energy sales	$	36.5	$	40.7	$	113.6	$	138.4
Energy capacity revenue		37.9		44.0		85.7		113.2
Other		34.2		16.5		131.7		54.2
		108.6		101.2		331.0		305.8
Project expenses:
Fuel		26.2		36.8		79.1		110.8
Operations and maintenance		19.8		28.2		63.4		79.4
Depreciation and amortization		31.4		25.3		90.5		75.6
		77.4		90.3		233.0		265.8
Project other income:
Change in fair value of derivative instruments (Notes 6 and 7)		(1.9)		9.0		(5.8)		20.0
Equity in earnings (loss) of unconsolidated affiliates (Note 3)		9.2		9.6		(36.1)		27.9
Interest, net		(2.2)		(2.4)		(6.6)		(6.9)
Impairment (Note 4)		(57.3)		(84.7)		(57.3)		(84.7)
Other income, net		0.1		0.5		0.1		0.4
		(52.1)		(68.0)		(105.7)		(43.3)
Project loss		(20.9)		(57.1)		(7.7)		(3.3)
Administrative and other expenses:
Administration		5.5		5.7		17.6		17.6
Interest expense, net		13.8		20.0		49.5		87.9
Foreign exchange loss (gain)		9.4		(3.4)		17.7		19.1
Other income, net		—		(1.7)		—		(3.9)
		28.7		20.6		84.8		120.7
Loss from operations before income taxes		(49.6)		(77.7)		(92.5)		(124.0)
Income tax (benefit) expense (Note 8)		(15.9)		2.6		(38.5)		(14.2)
Net loss		(33.7)		(80.3)		(54.0)		(109.8)
Net (loss) income attributable to preferred shares of a subsidiary company		(0.8)		2.1		3.5		6.4
Net loss attributable to Atlantic Power Corporation	$	(32.9)	$	(82.4)	$	(57.5)	$	(116.2)
Net loss per share attributable to Atlantic Power Corporation shareholders: (Note 10)
Basic	$	(0.29)	$	(0.69)	$	(0.50)	$	(0.96)
Diluted		(0.29)		(0.69)		(0.50)		(0.96)
Weighted average number of common shares outstanding: (Note 10)
Basic		115.3		119.3		115.1		120.9
Diluted		115.3		119.3		115.1		120.9

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in millions of U.S. dollars)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net loss	$	(33.7)	$	(80.3)	$	(54.0)	$	(109.8)
Other comprehensive loss, net of tax:
Unrealized loss on hedging activities	$	—	$	—	$	(0.3)	$	(0.6)
Net amount reclassified to earnings		0.1		0.2		0.5		0.5
Net unrealized gain (loss) on derivatives		0.1		0.2		0.2		(0.1)
Defined benefit plan, net of tax		—		—		0.1		—
Foreign currency translation adjustments		9.2		(22.0)		15.9		(2.6)
Other comprehensive income (loss), net of tax		9.3		(21.8)		16.2		(2.7)
Comprehensive loss		(24.4)		(102.1)		(37.8)		(112.5)
Less: Comprehensive (loss) income attributable to preferred share dividends of a subsidiary company		(0.8)		2.1		3.5		6.4
Comprehensive loss attributable to Atlantic Power Corporation	$	(23.6)	$	(104.2)	$	(41.3)	$	(118.9)

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)


	Nine months ended
	September 30,
	2017		2016
Cash provided by operating activities:
Net loss	$	(54.0)	$	(109.8)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		90.5		75.6
Gain on purchase and cancellation of convertible debentures		—		(4.7)
Loss on disposal of fixed assets		0.1		0.2
Stock-based compensation		1.6		1.4
Long-lived asset and goodwill impairment		57.3		84.7
Equity in loss (earnings) from unconsolidated affiliates		36.1		(27.9)
Distributions from unconsolidated affiliates		30.9		36.5
Unrealized foreign exchange loss		17.0		19.1
Change in fair value of derivative instruments		5.8		(20.0)
Amortization of debt discount and deferred financing costs		7.8		41.7
Change in deferred income taxes		(42.1)		(16.8)
Change in other operating balances
Accounts receivable		(11.5)		—
Inventory		(4.2)		1.1
Prepayments and other assets		0.6		0.3
Accounts payable		0.3		0.4
Accruals and other liabilities		1.7		10.1
Cash provided by operating activities		137.9		91.9
Cash (used in) provided by investing activities:
Change in restricted cash		0.8		2.6
Reimbursement of costs for third party construction project		—		4.7
Purchase of property, plant and equipment		(5.7)		(6.5)
Cash (used in) provided by investing activities		(4.9)		0.8
Cash used in financing activities:
Proceeds from term loan facility, net of discount		—		679.0
Common share repurchases		(0.2)		(13.9)
Preferred share repurchase		(3.1)		—
Repayment of corporate and project-level debt		(86.3)		(526.4)
Repayment of convertible debentures		(0.1)		(187.4)
Deferred financing costs		—		(16.2)
Dividends paid to preferred shareholders		(6.5)		(6.4)
Cash used in financing activities:		(96.2)		(71.3)
Net increase in cash and cash equivalents		36.8		21.4
Cash and cash equivalents at beginning of period		85.6		72.4
Cash and cash equivalents at end of period	$	122.4	$	93.8
Supplemental cash flow information
Interest paid	$	44.2	$	43.3
Income taxes paid, net	$	3.4	$	2.8
Accruals for construction in progress	$	—	$	0.4

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 September 30, 2017, our power generation projects 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 power generation projects across nine states in the United States and two provinces in Canada. Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis. The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence before June 2019. Eighteen of our projects are majority‑owned.

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 condensed 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, 2016. Interim results are not necessarily indicative of results for the full year.

In our opinion, the accompanying unaudited interim condensed consolidated financial statements present fairly our consolidated financial position as of September 30, 2017, the results of operations and comprehensive (loss) income for the three and nine months ended September 30, 2017 and 2016, and our cash flows for the nine months ended September 30, 2017 and 2016 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

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

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 useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible 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, 2016. 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

Issued

In May 2014, the Financial Accounting Standards Board (“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 was not permitted before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements. We have developed and are executing a project plan to assess the potential impact of the standard and have evaluated the majority of our most significant contracts (PPAs). We have approximately 12 PPAs at our consolidated projects that require further analysis under this standard. Currently we recognize energy revenue upon transmission to the customer. Capacity revenue is recognized when billed as hours are made available under the terms of the relevant PPA. Our current policy appears to be in compliance with the new standard’s focus on when the customer obtains control of the goods or services. However, these agreements are complex and still require analysis prior to reaching a conclusion as to how the adoption of the standard will impact our financial position, results of operations and cash flows. Upon adoption, we expect to utilize the cumulative-effect adjustment method upon adoption as of January 1, 2018.

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

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

permitted. We expect to elect certain of the practical expedients permitted, including the expedient that permits us to retain our existing lease assessment and classification. We are currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While we are currently evaluating the impact the new guidance will have on our financial position and results of operations, we expect to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending our review of our existing lease contracts and PPAs currently accounted for as operating leases. As this review is still in process, it is currently not practicable to quantify the impact of adopting this guidance at this time.

In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material impact on the consolidated financial statements.

In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the recognition of current and deferred incomes taxes for intra-entity asset transfers. Under the new guidance, current and deferred income tax consequences of an intra-entity asset transfer, other than an intra-entity asset transfer of inventory, are now recognized when the transfer occurs. The guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2017 with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements.

In November 2016, the FASB issued authoritative guidance to address diversity in practice of presenting changes in restricted cash on the statement of cash flows. The new guidance requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Adoption of this guidance will be applied retrospectively. This guidance will change our presentation of restricted cash in the consolidated statements of cash flows upon adoption. If this guidance was adopted for the nine months ended September 30, 2017, cash flows provided by operations would decrease by $0.8 million and cash flows used in investing activities would increase by $0.8 million, and for the nine months ended September 30, 2016, cash flows provided by operating activities would increase by $2.6 million and cash flows used in investing activities would decrease by $2.6 million.

In January 2017, the FASB issued authoritative guidance , which removes the requirement to perform a hypothetical purchase price allocation to measure goodwill impairment. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This guidance is effective for us for annual and interim periods beginning January 1, 2020, with early adoption permitted, and applied prospectively. We plan to adopt this guidance at the earlier of an event-driven impairment test in 2017 or when we perform our annual goodwill impairment test in the fourth quarter of 2017. We cannot assess the impact on our financial statements because the determination will be made based on a fair value measurement at the time the test is conducted.

In May 2017, the FASB issued authoritative guidance to address diversity in practice and cost and complexity of applying the guidance relating to stock compensation to a change to the terms or conditions of a share-based payment

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

award. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the potential impact of the adoption on the consolidated financial statements.

In August 2017, the FASB issued authoritative guidance to align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. The guidance expands and refines hedge accounting for both nonfinancial and financial risk components and aligns the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the potential impact of the adoption on the 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)

2. Changes in accumulated other comprehensive loss by component

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Foreign currency translation
Balance at beginning of period	$	(141.6)	$	(119.7)	$	(148.3)	$	(139.1)
Other comprehensive loss:
Foreign currency translation adjustments (1)		9.2		(22.0)		15.9		(2.6)
Balance at end of period	$	(132.4)	$	(141.7)	$	(132.4)	$	(141.7)
Pension
Balance at beginning of period	$	(0.8)	$	(0.4)	$	(0.9)	$	(0.4)
Other comprehensive loss:
Curtailment gain		—		—		0.1		—
Tax benefit (expense)		—		—		—		—
Total Other comprehensive (loss) income before reclassifications, net of tax		—		—		0.1		—
Total amount reclassified from accumulated other comprehensive loss, net of tax		—		—		—		—
Total other comprehensive income		—		—		0.1		—
Balance at end of period	$	(0.8)	$	(0.4)	$	(0.8)	$	(0.4)
Cash flow hedges
Balance at beginning of period	$	0.8	$	(0.1)	$	0.7	$	0.2
Other comprehensive loss:
Net change from periodic revaluations		(0.1)		0.1		(0.6)		(1.0)
Tax benefit (expense)		0.1		(0.1)		0.3		0.4
Total Other comprehensive loss before reclassifications, net of tax		—		—		(0.3)		(0.6)
Net amount reclassified to earnings:
Interest rate swaps (2)		0.2		0.3		0.9		0.9
Tax expense		(0.1)		(0.1)		(0.4)		(0.4)
Total amount reclassified from accumulated other comprehensive loss, net of tax		0.1		0.2		0.5		0.5
Total other comprehensive income (loss)		0.1		0.2		0.2		(0.1)
Balance at end of period	$	0.9	$	0.1	$	0.9	$	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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

3. Equity method investments in unconsolidated affiliates

The following summarizes the operating results for the three and nine months ended September 30, 2017 and 2016, respectively, for our proportional ownership interest in equity method investments:


	Three Months Ended September 30,				Nine Months Ended September 30,
Operating results	2017		2016		2017		2016
Revenue
Frederickson	$	5.9	$	5.8	$	16.0	$	15.7
Orlando Cogen, LP		14.3		13.9		40.4		40.6
Koma Kulshan Associates		0.3		0.1		1.4		1.3
Chambers Cogen, LP		10.5		11.2		33.1		34.3
Selkirk Cogen Partners, LP		—		3.1		1.8		5.9
		31.0		34.1		92.7		97.8
Project expenses
Frederickson		4.9		4.9		16.8		14.3
Orlando Cogen, LP		7.2		6.9		22.1		19.6
Koma Kulshan Associates		0.3		0.4		0.8		0.9
Chambers Cogen, LP		8.9		9.3		27.2		27.8
Selkirk Cogen Partners, LP		—		2.6		2.8		5.9
		21.3		24.1		69.7		68.5
Project other expense
Frederickson		—		—		—		—
Orlando Cogen, LP		—		—		—		—
Koma Kulshan Associates		—		—		—		—
Chambers Cogen, LP		(0.5)		(0.4)		(48.5)		(1.4)
Selkirk Cogen Partners, LP		—		—		(10.6)		—
		(0.5)		(0.4)		(59.1)		(1.4)
Project income (loss)
Frederickson		1.0		0.9		(0.8)		1.4
Orlando Cogen, LP		7.1		7.0		18.3		21.0
Koma Kulshan Associates		—		(0.3)		0.6		0.4
Chambers Cogen, LP		1.1		1.5		(42.6)		5.1
Selkirk Cogen Partners, LP		—		0.5		(11.6)		—
Equity in earnings (loss) of unconsolidated affiliates	$	9.2	$	9.6	$	(36.1)	$	27.9

Distributions from equity method investments		(13.7)		(13.0)		(30.9)		(36.5)
Deficit in earnings of equity method investments, net of distributions	$	(4.5)	$	(3.4)	$	(67.0)	$	(8.6)

We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long ‑ term investments. Therefore, we complete our assessments with a long ‑ term view. If the fair value of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value.

In the second quarter of 2017, we performed impairment tests at our Chambers and Selkirk projects, which are accounted for under the equity method of accounting.

Selkirk

We own a 17.7% limited partner interest in Selkirk Cogen Partners, L.P. The project has operated as a merchant facility since the expiration of its PPA in August 2014. Since the expiration of its PPA, we have not received a distribution from Selkirk and have recorded a cumulative $1.2 million project loss. Based on the project’s history of providing no cash distributions while operating as a merchant facility, the short-term and long-term operational forecast, as well as the likelihood that further investment will be required in order to operate the facility, we determined that our investment in Selkirk is impaired and the decline in value is other than temporary. Accordingly, we recorded a $10.6 million full impairment in earnings from unconsolidated affiliates in the consolidated statements of operations in the second quarterly period of 2017.

Chambers

We own a 40% limited partner interest in Chambers Cogeneration Limited Partnership. The Chambers project operates under a PPA that expires in March 2024. Prior to our impairment analysis, Chambers was recorded as a $124 million component of our equity investments in unconsolidated affiliates on the consolidated balance sheets. We have recorded equity earnings of $3.4 million, $5.5 million and $6.5 million for the six months ended June 30, 2017, year ended December 31, 2016 and year ended December 31, 2015, respectively. During those periods, we also received cumulative distributions of $33.6 million from Chambers.

During the second quarter of 2017, we performed an analysis of the post-PPA value of Chambers operating as a merchant facility. While declining power prices have been observed over the past several years, in our most recent long-term forecast, we identified a significant decrease in the long-term outlook for power prices in the region where Chambers operates. These forward prices, which were obtained from a third party, including forward prices of gas and coal, had a significant negative impact on the estimated discounted cash flows (“DCFs”) of Chambers post-PPA. The estimated post-PPA value is a significant component of the project’s overall value when compared to its carrying value of $124 million.

When determining if this decrease in value is other than temporary, we considered the likelihood that future conditions would change such that the gas and coal prices currently observed in the forward pricing models would become more favorable over time in order for the plant to be profitable in a merchant market. We also engaged a separate third party to provide its outlook on post-PPA value for Chambers. It is our assessment that gas prices are likely to remain low when considering the current and expected future supply of shale gas. The third party provided similar conclusions to our assessment.

Based on these factors, we determined that the decline in the fair value of our equity investment in Chambers is other than temporary. We recorded a $47.1 million impairment in earnings from unconsolidated affiliates in the consolidated statements of operations for the three months ended June 30, 2017. After recording the impairment, our equity investment in Chambers is $77.2 million, which represents its estimated fair value at June 30, 2017.

We determine the fair value of our equity investments using an income approach with DCF models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The discounted cash flows utilized in our impairment tests are generally based on approved operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular investment and is based upon an assumed capital structure, cost of long ‑ term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third party sources. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of an equity method investment.

The valuation of equity method investments is considered a level 3 fair value measurement, which means that the valuation of the investments reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the investments. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of an equity investment impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our investments may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.

4. Long-lived assets and goodwill

2017

We test our long-lived assets and goodwill for impairment at least annually, or more often if deemed appropriate based on management’s determination of the occurrence of certain trigger events under our impairment

policy. When we have an expectation that we will be unable to renew or renegotiate a PPA, the value of the project may be impaired such that we would record an impairment loss.

Naval Station, North Island and Naval Training Center (“NTC”) (collectively, the “San Diego Projects”) sell power to San Diego Gas & Electric (“SDG&E”) under PPAs that are scheduled to expire in December 2019. In addition, the three projects supply steam to the U.S. Navy under agreements that provide these projects with the right to use the property at the respective sites on which each project is located (the "Navy agreements"). In August 2017, we were unsuccessful in obtaining contracts to provide the Navy with energy security that would have provided us with the right to use the Naval Station and North Island sites beyond February 2018. Following notification of the outcome of the Navy solicitation, we determined that it was unlikely that these projects will operate beyond the expiration of the Navy agreements. As a result, we performed long-lived asset impairment tests at each of these projects as of July 31, 2017.

In order to test the recoverability of the long-lived assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by each of the San Diego Projects through their expected decommissioning dates. The carrying value of each asset group includes its recorded property, plant equipment and intangible assets related to PPAs. As a result of this test, we recorded a total $57.3 million impairment ($22.5 million at Naval Station, $13.5 million at NTC and $21.2 million at North Island) in the three and nine months ended September 30, 2017. This impairment is composed of an $18.2 million full impairment of intangible assets related to PPAs ($10.3 million at Naval Station, $3.6 million at NTC and $4.2 million at North Island) and a $39.1 million partial impairment of property, plant and equipment ($12.1 million at Naval Station, $9.9 million at NTC and $17.0 million at North Island). After recording the impairment, the San Diego projects have $7.7 million of property,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

plant and equipment at September 30, 2017, which represents our estimate of fair value based on the projects’ remaining undiscounted cash flows and salvage values. The San Diego projects have net removal obligations recorded of $4.6 million at September 30, 2017. We are in the process of evaluating the estimated removal costs and may have further adjustments to this amount in the three months ended December 31, 2017 as t he timing and final arrangements for decommissioning the sites have not been determined.

2016

In the third quarter of 2016, we performed an event-driven goodwill impairment test. While declining power prices have been observed over the prior two years, we identified a significant decrease in the long-term outlook for power prices in the regions where our reporting units operate in the third quarter of 2016. Because the estimated future cash flows of our reporting units are sensitive to fluctuations in forward power prices and these prices are the most impactful input in calculating a reporting unit’s fair value, we determined that it was appropriate to perform an event-driven impairment test. For two of our reporting units (Morris and Nipigon) we performed a qualitative assessment and concluded that it was likely that the fair values significantly exceed the carrying values. These reporting units have aggregate goodwill of $6.9 million and have PPAs with significant remaining time before their expiration and are not significantly impacted by the decrease in the long-term outlook for power prices.

The other five of the reporting units tested (Curtis Palmer, Mamquam, North Bay, Kapuskasing and Moresby Lake) failed step 1 of our quantitative two‑step test. Because five reporting units failed step 1 of the two-step goodwill impairment test, we identified a triggering event and initiated a test of the recoverability of their long-lived assets. The asset group for testing the long-lived assets for impairment is the same as the reporting unit for goodwill impairment testing purposes. In order to test the recoverability of the assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by the asset group. The carrying value of each asset group includes its recorded property, plant equipment, intangible assets related to PPAs and goodwill. Of the five asset groups tested, the North Bay and Kapuskasing asset groups (Canada segment) failed the recoverability test and we recorded property, plant and equipment impairment charges aggregating $5.9 million for the periods ended September 30, 2016. For these asset groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These assumptions include estimated cash flows under the remaining period of their respective PPAs.

Subsequent to recording long-lived asset impairments, we performed the step 2 goodwill impairment test and recorded a $50.2 million full impairment at the Mamquam reporting unit, a $15.4 million partial impairment at the Curtis Palmer reporting unit, a $6.5 million full impairment at the North Bay reporting unit, a $6.7 million full impairment at the Kapuskasing reporting unit and no impairment at the Moresby Lake reporting unit for a total goodwill impairment charge of $78.8 million for the periods ended September 30, 2016. At the time of their acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Mamquam and Curtis Palmer reporting units were valued assuming a merchant basis for the period subsequent to the expiration of the projects’ original PPAs. The forecasted energy revenue on a merchant basis, in the respective markets in which those plants operate, was higher than the energy prices currently forecasted to be in effect subsequent to the expiration of the reporting unit’s PPA. Power prices, in the respective markets in which those plants operate, have declined from 2011 and from the dates of our previous impairment assessments due to several factors including decreased demand, lower oil prices and lower natural gas prices resulting from an abundance of shale gas. Our forecasts for DCFs also reflect a higher level of uncertainty for re‑contracting at prices than were previously forecasted in 2011. The decline in forward power prices for British Columbia since our prior goodwill impairment performed as of November 30, 2015, in particular, had a significant impact on the estimated DCFs of our Mamquam reporting unit and was the primary driver for its recorded goodwill impairment. British Columbia’s peak demand outlook has declined primarily due to a reduction in forecasted liquefaction build and need in the region and the associated loss of power demand. The resulting drop in the peak demand reduces the amount of needed capacity and therefore the capacity prices also were reduced. Furthermore, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

PPA at the Curtis Palmer reporting unit expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. Based on Curtis Palmer’s cumulative generation through the date of the goodwill impairment test, we anticipate the PPA expiring two years before December 2027. As a result, the DCF model for Curtis Palmer utilizes forward power prices for that two-year period that are substantially lower than the prices under the current PPA.

The long-lived asset and goodwill impairment charges were recorded in the third quarter of 2016 and not earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven impairment assessment. While declining power prices have been observed over the past two years, the significant decrease in the long-term outlook for power prices in the regions where our reporting units operate identified in the third quarter of 2016 had the most significant impact to the key inputs to our long-term forecasted cash flow models. Additionally, the PPAs at our North Bay and Kapuskasing reporting units expire on December 31, 2017. As these projects approach the expiration date, the remaining estimated contracted future cash flows decrease.

We determine the fair value of our reporting units using an income approach with DCF models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long‑lived asset recovery and step 1 and 2 goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents WACC consistent with the risk inherent in future cash flows of the particular reporting unit and is based upon an assumed capital structure, cost of long‑term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third-party sources. We utilized the assistance of valuation experts to perform step 1 and step 2 of the quantitative impairment test for several of our reporting units. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill.

The valuation of long-lived assets and goodwill for the impairment analyses is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.

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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:


	September 30,		December 31,
	2017		2016		Interest Rate
Recourse Debt:
Senior secured term loan facility, due 2023 (1)	$	562.7	$	639.9	LIBOR (2)	plus	4.25	%
Senior unsecured notes, due June 2036 (Cdn$210.0)		168.3		156.4			5.95	%
Non-Recourse Debt:
Epsilon Power Partners term facility, due 2019		8.8		13.5	LIBOR	plus	3.130	%
Cadillac term loan, due 2025		24.8		27.0	LIBOR	plus	1.37	%
Piedmont term loan, due 2018 (3)		54.6		56.6	LIBOR	plus	3.75	%
Other long-term debt		—		0.2	5.50	% -	6.70	%
Less: unamortized discount		(13.8)		(17.2)
Less: unamortized deferred financing costs		(11.6)		(15.3)
Less: current maturities		(156.5)		(111.9)
Total long-term debt	$	637.3	$	749.2

Current maturities consist of the following:


	September 30,		December 31,
	2017		2016		Interest Rate
Current Maturities:
Senior secured term loan facility, due 2023 (1)	$	92.5	$	100.0	LIBOR (2)	plus	4.25	%
Epsilon Power Partners term facility, due 2019		6.4		6.2	LIBOR	plus	3.130	%
Cadillac term loan, due 2025		3.0		3.0	LIBOR	plus	1.37	%
Piedmont term loan, due 2018 (3)		54.6		2.5	LIBOR	plus	3.75	%
Other short-term debt		—		0.2	5.50	% -	6.70	%
Total current maturities	$	156.5	$	111.9

⁽¹⁾

On a quarterly basis, we make a cash sweep payment to fund the principal balance, based on terms as defined in the term loan credit agreement. 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 senior secured term loan outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule.

⁽²⁾

LIBOR cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $ 354.0 million of the $562.7 million outstanding aggregate borrowings under our senior secured term loan facility at September 30, 2017. See Note 7, Accounting for derivative instruments and hedging activities for further details. On October 18, 2017, the repricing of the $562.7 million senior secured term loan facility became effective. As a result of the repricing, the interest rate margin on the term loan and revolver was reduced by 0.75% to LIBOR plus 3.50%. On October 30, 2017, we also extended the maturity date of our $200 million senior secured revolving credit facility by one year through April 13, 2022.

⁽³⁾

On October 13, 2017, we repaid the $54.6 million Piedmont term loan due August 2018, in full, with cash on hand. In addition to the principal repayment, we paid $0.1 million of accrued interest, $9.4 million to terminate interest rate swap agreements and wrote off $0.9 million of deferred financing costs. The swap termination costs and deferred financing costs write down will be recorded as interest expense in the three months ended December 31, 2017.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

6. 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 September 30, 2017 and December 31, 2016. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.


	September 30, 2017
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	122.4	$	—	$	—	$	122.4
Restricted cash		12.5		—		—		12.5
Derivative instruments asset		—		5.1		—		5.1
Total	$	134.9	$	5.1	$	—	$	140.0
Liabilities:
Derivative instruments liability	$	—	$	33.0	$	—	$	33.0
Total	$	—	$	33.0	$	—	$	33.0


	December 31, 2016
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	85.6	$	—	$	—	$	85.6
Restricted cash		13.3		—		—		13.3
Derivative instruments asset		—		8.6		—		8.6
Total	$	98.9	$	8.6	$	—	$	107.5
Liabilities:
Derivative instruments liability	$	—	$	28.9	$	—	$	28.9
Total	$	—	$	28.9	$	—	$	28.9

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 September 30, 2017, the credit valuation adjustments resulted in a $2.4 million net increase in fair value, which consists of a $0.2 million pre‑tax gain in other comprehensive income and a $2.2 million gain in change in fair value of derivative instruments. As of December 31, 2016, the credit valuation adjustments resulted in a $3.8 million net increase in fair value, which consists of a $0.3 million pre‑tax gain in other comprehensive income and a $3.5 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

7. 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 and sale agreements

We have entered into various gas purchase and sale agreements for our Nipigon projects that expire ranging from October 31, 2018 through December 31, 2022. In June 2014, Atlantic Power Limited Partnership 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. In December 2016, we entered into a gas purchase agreement for our Kenilworth project to fix the price of 0.8 million Mmbtu of natural purchases beginning on January 1, 2017 and expiring on December 31, 2017. We have also entered into various natural gas sales and purchase agreements for approximately 220,000 Mmbtu to effectively mitigate seasonal fluctuation of future natural gas prices at Morris through February 2018. These agreements do not qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments because we could not conclude that it is probable that these contracts will not settle net and will result in physical delivery. 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.

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 10.9 million Mmbtu of future natural gas purchases at Orlando, which is approximately 95%, 90%, 100% and 50% of our share of the expected natural gas purchases at the project in 2017, 2018, 2019 and 2020, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at September 30, 2017. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.

Interest rate swaps

Atlantic Power Limited Partnership 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 $354.2 million notional amount of the $562.7 million aggregate principal amount of borrowings under the senior secured term loans outstanding as of September 30, 2017. These interest rate swap agreements expire at various dates through March 31, 2020. Borrowings under the senior secured term loans bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 4.25%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 5.25% all-in rate on the senior secured term loans . As a result of entering into the swap agreements, the all-in rate for $375.7 million of the senior secured term loans cannot be less than 5.25%, if the Adjusted Eurodollar Rate is equal to or greater than 1.00%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

The Piedmont project had interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable‑rate debt. The interest rate swap agreements effectively converted the floating rate debt from LIBOR plus an applicable margin of 3.75% to a fixed rate of 4.47% plus an applicable margin of 4.00% until the maturity of the debt in August 2018, resulting in an all‑in rate of 8.47%. The interest rate swaps were set to expire on November 30, 2030. The interest rate swap agreements were not designated as hedges, and changes in their fair market value were recorded in the consolidated statements of operations. In October 2017, the swaps were settled due to early repayment of the term loan. The settlement resulted in $9.4 million of interest expense, which will be recorded as interest expense in the three months ended December 31, 2017.

The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.1% through 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.

Foreign currency forward contracts

We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates as we generate cash flow in U.S. dollars and Canadian dollars. We currently have Canadian dollar payment obligations for preferred dividends, interest on our Canadian dollar-denominated convertible debentures and our Medium Term Notes. Principal and interest payments for our senior secured term loans as well as our U.S dollar-denominated convertible debentures are made in U.S. dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the future interest and principal payments, preferred dividends and other working capital requirements. In March 2017, we entered into foreign exchange forward contracts to sell a total of Cdn$30 million at an exchange rate of 1.3381 in Cdn$10.0 million tranches on each of June 2017, September 2017 and December 2017.

In July 2017, we entered into additional foreign exchange forward contracts to sell a total of Cdn$10 million at an exchange rate of 1.2481 in Cdn$3.33 million tranches on each of March 2018, June 2018 and December 2018. In July 2017, we also entered into foreign exchange forward contracts to sell a total of Cdn$10 million at an exchange rate of 1.2943 in tranches of Cdn$5.0 million in March 2018, Cdn$3.0 million in June 2018 and Cdn$2.0 million in December 2018. In September 2017, we entered into foreign exchange forward contracts to sell Cdn$5.0 million at an exchange rate of 1.2196 in September 2018.

Foreign currency forward contracts are not designated as hedges, and changes in their market value are recorded in foreign exchange on the consolidated statements of operations at September 30, 2017.

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 NPNS exemption at September 30, 2017 and December 31, 2016:


		September 30,	December 31,
	Units	2017	2016
Natural gas swaps	Natural Gas (Mmbtu)	9.0	4.9
Gas purchase agreements	Natural Gas (Gigajoules)	10.5	11.3
Interest rate swaps	Interest (US$)	434.6	506.9
Foreign currency forward contracts	Dollars (Cdn$)	35.0	-

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Fair value of derivative instruments

We 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 :


	September 30, 2017
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.7
Interest rate swaps long-term		—		1.8
Total derivative instruments designated as cash flow hedges		—		2.5
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		1.4		8.8
Interest rate swaps long-term		2.6		—
Natural gas swaps current		0.4		0.1
Natural gas swaps long-term		—		—
Gas purchase agreements current		0.7		3.3
Gas purchase agreements long-term		—		17.7
Foreign currency forward contracts current		—		0.6
Total derivative instruments not designated as cash flow hedges		5.1		30.5
Total derivative instruments	$	5.1	$	33.0


	December 31, 2016
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.8
Interest rate swaps long-term		—		2.0
Total derivative instruments designated as cash flow hedges		—		2.8
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		0.4		1.9
Interest rate swaps long-term		4.5		6.5
Natural gas swaps current		3.9		0.8
Natural gas swaps long-term		0.1		—
Gas purchase agreements current		—		4.5
Gas purchase agreements long-term		—		12.7
Total derivative instruments not designated as cash flow hedges		8.9		26.4
Total derivative instruments	$	8.9	$	29.2

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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 September 30, 2017	Swaps
Accumulated OCI balance at June 30, 2017	$	0.8
Change in fair value of cash flow hedges		—
Realized from OCI during the period		0.1
Accumulated OCI balance at September 30, 2017	$	0.9

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

	Interest Rate
Nine Months Ended September 30, 2017	Swaps
Accumulated OCI balance at January 1, 2017	$	0.7
Change in fair value of cash flow hedges		(0.3)
Realized from OCI during the period		0.5
Accumulated OCI balance at September 30, 2017	$	0.9

	Interest Rate
Nine Months Ended September 30, 2016	Swaps
Accumulated OCI balance at January 1, 2016	$	0.2
Change in fair value of cash flow hedges		(0.6)
Realized from OCI during the period		0.5
Accumulated OCI balance at September 30, 2016	$	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 September 30,				Nine Months Ended September 30,
	recognized in income	2017		2016		2017		2016
Gas purchase agreements	Fuel	$	3.1	$	12.4		7.9	$	36.4
Natural gas swaps	Fuel		(0.7)		0.6		(1.2)		4.0
Interest rate swaps	Interest, net		0.9		1.0		2.6		2.7

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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 gain (loss) 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 September 30,				Nine Months Ended September 30,
	recognized in income	2017		2016		2017		2016
Natural gas swaps	Change in fair value of derivatives	$	0.2	$	0.2	$	(0.3)	$	6.0
Gas purchase agreements	Change in fair value of derivatives		(1.3)		5.6		(4.3)		16.8
Interest rate swaps	Change in fair value of derivatives		(0.8)		3.2		(1.2)		(2.8)
		$	(1.9)	$	9.0	$	(5.8)	$	20.0
Foreign currency forwards	Foreign exchange loss	$	(0.2)	$	—	$	(0.7)	$	—

8. Income taxes


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Current income tax expense	$	1.3	$	0.8	$	3.6	$	2.6
Deferred income (benefit) expense		(17.2)		1.8		(42.1)		(16.8)
Total income tax (benefit) expense, net	$	(15.9)	$	2.6	$	(38.5)	$	(14.2)

For the three and nine months ended September 30, 2017 and 2016

Income tax benefit for the three months ended September 30, 2017 was $15.9 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $12.9 million. The primary items impacting the tax rate for the three months ended September 30, 2017 were $3.5 million related to a net increase to the Company's valuation allowances in Canada and $0.3 million of other permanent differences. These items were offset by $5.5 million relating to operating in higher tax rate jurisdictions and $1.3 million relating to foreign exchange.

Income tax expense for the three months ended September 30, 2016 was $2.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $20.2 million. The primary item impacting the tax rate for the three months ended September 30, 2016 was $22.5 million related to goodwill impairment. In addition, the rate was further impacted by a net increase to our valuation allowances of $8.6 million, consisting primarily of increases of $9.3 million in Canada related to capital loss on intercompany notes, $1.9 million relating to operating in higher tax rate jurisdictions and $0.8 million of other permanent differences.

Income tax benefit for the nine months ended September 30, 2017 was $38.5 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $24.1 million. The primary items impacting the tax rate for the nine months ended September 30, 2017 were $1.5 million related to a net increase to the Company's valuation allowances in Canada and $0.6 million relating to income taxes. These items were offset by $14.2 million relating to operating in higher tax rate jurisdictions and $2.3 million relating to foreign exchange.

Income tax benefit for the nine months ended September 30, 2016 was $14.2 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $32.2 million. The primary items impacting the tax rate for the nine months ended September 30, 2016 were $22.5 million relating to goodwill impairment, $5.5 million relating to foreign exchange and $1.1 million of other permanent differences. In addition, the rate was further impacted by a net increase to the Company’s valuation allowances of $13.2 million, consisting primarily of increases of $31.6 million in Canada related to losses and a decrease of $18.4 million in the United States due to tax restructurings and additional earnings. These items were offset by $18.5 million Canadian capital losses recognized on

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

tax restructurings, $3.0 million related to capital loss on intercompany notes and $2.8 million relating to operating in higher tax rate jurisdictions.

As of September 30, 2017, we have recorded a valuation allowance of $ 187.5 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.

9. Equity compensation plans

Long‑term incentive plan (“LTIP”)

The following table summarizes the changes in outstanding LTIP notional units during the nine months ended September 30, 2017:


		Grant Date
		Weighted-Average
	Units	Fair Value per Unit
Outstanding at December 31, 2016	2,101,118		2.08
Granted	1,817,463		2.38
Vested and redeemed	(1,009,780)		2.22
Forfeitures	(24,227)		2.32
Outstanding at September 30, 2017	2,884,574	$	2.22

Cash payments made for vested notional units for the nine months ended September 30, 2017 and 2016 were $0.7 million and $0.4 million, respectively. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $0.9 million and $2.6 million for the three and nine months ended September 30, 2017 and $0.8 million and $0.9 million for the three and nine months ended September 30, 2016, respectively.

Transition Equity Participation Agreement

We also have 539,904 transition notional shares outstanding at September 30, 2017 under the Transition Equity Participation Agreement with James J. Moore, Jr. Fifty percent of the transition notional shares granted in January 2015 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% (Cdn$4.77).

10. Basic and diluted loss per share

Basic loss per share is calculated by dividing net loss by the weighted average common shares outstanding during their respective periods. Diluted 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 nine months ended September 30, 2017 and 2016, respectively, 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 nine months ended September 30, 2017 and 2016:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Numerator:
Net loss attributable to Atlantic Power Corporation	$	(32.9)	$	(82.4)	$	(57.5)	$	(116.2)
Denominator:
Weighted average basic shares outstanding		115.3		119.3		115.1		120.9
Dilutive potential shares:
Convertible debentures		8.1		8.1		8.1		14.9
LTIP notional units		—		0.1		—		0.1
Potentially dilutive shares		123.4		127.5		123.2		135.9
Basic and diluted loss per share attributable to Atlantic Power Corporation	$	(0.29)	$	(0.69)	$	(0.50)	$	(0.96)

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, would be added back to the numerator for purposes of the if-converted calculation. Potentially dilutive shares from convertible debentures of $8.1 million and $8.1 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2017, respectively, because their impact would be anti-dilutive. Potentially dilutive shares from convertible debentures of $8.1 million and $14.9 million have been excluded from fully diluted shares in the three and nine months ended September 30, 2016, respectively, because their impact would be anti-dilutive.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

11. 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 and total equity for the nine months ended September 30, 2017 and 2016:


	Nine months ended September 30, 2017
	Total Atlantic		Preferred shares
	Power Corporation		issued by a subsidiary
	Shareholders’ Equity		company		Total Equity
Balance at January 1, 2017	$	64.6	$	221.3	$	285.9
Net (loss) income		(57.5)		3.5		(54.0)
Realized and unrealized gain on hedging activities, net of tax		0.2		—		0.2
Foreign currency translation adjustment		15.9		—		15.9
Defined benefit plan, net of tax		0.1		—		0.1
Common share repurchases		(0.2)		—		(0.2)
Preferred share repurchases		—		(3.1)		(3.1)
Stock-based compensation		1.6		—		1.6
Dividends declared on preferred shares of a subsidiary company		—		(6.5)		(6.5)
Balance at September 30, 2017	$	24.7	$	215.2	$	239.9


	Nine months ended September 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		(116.2)		6.4		(109.8)
Realized and unrealized loss on hedging activities, net of tax		(0.1)		—		(0.1)
Foreign currency translation adjustment		(2.6)		—		(2.6)
Common share repurchases		(13.9)		—		(13.9)
Stock-based compensation		1.4		—		1.4
Dividends declared on preferred shares of a subsidiary company		—		(6.4)		(6.4)
Balance at September 30, 2016	$	82.5	$	221.3	$	303.8

Stock Repurchase Program

In December 2015, our Board of Directors approved a normal course issuer bid (“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 permitted the Company to repurchase stock through open market repurchases. The NCIB expired on December 28, 2016. Through September 30, 2016, we repurchased and cancelled 5.7 million common shares at a total cost of $13.9 million. For the year ended December 31, 2016, we repurchased a cumulative 8.0 million common shares at a total cost of $19.5 million. Repurchases and retirement of common shares are recorded to common shares on the consolidated balance sheets.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

On December 29, 2016, we commenced a new NCIB that will expire on December 28, 2017 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIBs . Under the new NCIB, we may purchase up to approximately 11.3 million common shares, or 10% of our public float. Through September 30, 2017, we repurchased and cancelled 0.1 million common shares at a cost of $0.2 million. Through September 30, 2017, we also repurchased and cancelled 0.3 million of our Cdn$25.0 par value 4.85% Cumulative Redeemable Preferred Shares, Series 1 at Cdn$15.5 per share for a total payment of Cdn$3.9 million, resulting in a $3.0 million gain recorded in net (loss) income attributable to preferred shares of a subsidiary company in the three and nine months ended September 30, 2017.

12. Segment and geographic information

We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. 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. We use Project Adjusted EBITDA to provide comparative information about segment 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 Project Adjusted EBITDA to net loss for the three and nine months ended September 30, 2017 and 2016 is included in the tables below:


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Three Months Ended September 30, 2017
Project revenues	$	39.8	$	35.1	$	33.5	$	0.2	$	108.6
Segment assets		680.9		237.5		281.9		113.6		1,313.9
Project Adjusted EBITDA	$	30.6	$	21.7	$	24.6	$	0.5	$	77.4
Change in fair value of derivative instruments		1.3		—		1.3		(0.6)		2.0
Depreciation and amortization		11.8		10.6		14.0		0.2		36.6
Interest, net		2.5		—		—		—		2.5
Impairment		—		57.3		—		—		57.3
Other project income		—		—		(0.1)		—		(0.1)
Project income (loss)		15.0		(46.2)		9.4		0.9		(20.9)
Administration		—		—		—		5.5		5.5
Interest expense, net		—		—		—		13.8		13.8
Foreign exchange loss		—		—		—		9.4		9.4
Income (loss) from continuing operations before income taxes		15.0		(46.2)		9.4		(27.8)		(49.6)
Income tax benefit		—		—		—		(15.9)		(15.9)
Net income (loss) from continuing operations	$	15.0	$	(46.2)	$	9.4	$	(11.9)	$	(33.7)

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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
Three Months Ended September 30, 2016
Project revenues	$	31.3	$	34.1	$	35.6	$	0.2	$	101.2
Segment assets		764.9		328.9		325.3		102.8		1,521.9
Project Adjusted EBITDA	$	19.4	$	21.3	$	10.7	$	(0.1)	$	51.3
Change in fair value of derivative instruments		(1.2)		—		(5.6)		(2.2)		(9.0)
Depreciation and amortization		11.0		9.9		9.4		0.1		30.4
Interest, net		2.8		—		—		—		2.8
Impairment		15.4		—		69.3		—		84.7
Other project income		—		—		—		(0.5)		(0.5)
Project (loss) income		(8.6)		11.4		(62.4)		2.5		(57.1)
Administration		—		—		—		5.7		5.7
Interest expense, net		—		—		—		20.0		20.0
Foreign exchange gain		—		—		—		(3.4)		(3.4)
Other income, net		—		—		—		(1.7)		(1.7)
(Loss) income from continuing operations before income taxes		(8.6)		11.4		(62.4)		(18.1)		(77.7)
Income tax expense		—		—		—		2.6		2.6
Net (loss) income from continuing operations	$	(8.6)	$	11.4	$	(62.4)	$	(20.7)	$	(80.3)


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Nine Months Ended September 30, 2017
Project revenues	$	116.3	$	86.2	$	127.8	$	0.7	$	331.0
Segment assets		680.9		237.5		281.9		113.6		1,313.9
Project Adjusted EBITDA	$	86.8	$	41.5	$	97.3	$	1.0	$	226.6
Change in fair value of derivative instruments		3.3		—		5.4		(2.9)		5.8
Depreciation and amortization		34.2		30.6		40.4		0.4		105.6
Interest, net		8.0		—		—		—		8.0
Impairment		—		57.3		—		—		57.3
Other project expense (income)		57.7		—		(0.1)		—		57.6
Project (loss) income		(16.4)		(46.4)		51.6		3.5		(7.7)
Administration		—		—		—		17.6		17.6
Interest expense, net		—		—		—		49.5		49.5
Foreign exchange loss		—		—		—		17.7		17.7
(Loss) income from continuing operations before income taxes		(16.4)		(46.4)		51.6		(81.3)		(92.5)
Income tax benefit		—		—		—		(38.5)		(38.5)
Net (loss) income from continuing operations	$	(16.4)	$	(46.4)	$	51.6	$	(42.8)	$	(54.0)

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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
Nine Months Ended September 30, 2016
Project revenues	$	104.3	$	78.7	$	122.0	$	0.8	$	305.8
Segment assets		764.9		328.9		325.3		102.8		1,521.9
Project Adjusted EBITDA	$	70.5	$	43.4	$	46.2	$	(0.2)	$	159.9
Change in fair value of derivative instruments		(3.0)		—		(17.7)		0.6		(20.1)
Depreciation and amortization		33.0		29.6		27.7		0.5		90.8
Interest, net		8.2		—		—		—		8.2
Impairment		15.4		—		69.3		—		84.7
Other project income		—		—		—		(0.4)		(0.4)
Project income (loss)		16.9		13.8		(33.1)		(0.9)		(3.3)
Administration		—		—		—		17.6		17.6
Interest expense, net		—		—		—		87.9		87.9
Foreign exchange loss		—		—		—		19.1		19.1
Other income, net		—		—		—		(3.9)		(3.9)
Income (loss) from continuing operations before income taxes		16.9		13.8		(33.1)		(121.6)	$	(124.0)
Income tax benefit		—		—		—		(14.2)		(14.2)
Net income (loss) from continuing operations	$	16.9	$	13.8	$	(33.1)	$	(107.4)	$	(109.8)

The table below provides information, by country, about our consolidated operations for each of the three and nine months ended September 30, 2017 and 2016 and Property, Plant & Equipment as of September 30, 2017 and December 31, 2016, 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 September 30,				Project Revenue Nine Months Ended September 30,				Property, Plant and Equipment, net of accumulated depreciation
	2017		2016		2017		2016		September 30, 2017		December 31, 2016
United States	$	75.1	$	65.6	$	203.2	$	183.8	$	437.0	$	499.2
Canada		33.5		35.6		127.8		122.0		215.6		234.0
Total	$	108.6	$	101.2	$	331.0	$	305.8	$	652.6	$	733.2

Independent Electricity System Operator (“IESO”), SDG&E, BC Hydro and Georgia Power Company provided 16.4%, 13.9%, 11.3% and 10.3%, respectively, of total consolidated revenues for the three months ended September 30, 2017. IESO, SDG&E, Niagara Mohawk and BC Hydro provided 19.3%, 11.1%, 10.7% and 10.3%, respectively, of total consolidated revenues for the nine months ended September 30, 2017. IESO, SDG&E, Georgia Power Company and BC Hydro provided 24.5%, 16.1%, 10.9% and 10.6%, respectively, of total consolidated revenues for the three months ended September 30, 2016. IESO, BC Hydro and SDG&E provided 28.0%, 11.6% and 11.5%, respectively, of total consolidated revenues for the nine months ended September 30, 2016. IESO and Ontario Electric Financial Corporation (“OEFC”) purchase electricity from the Calstock, Kapuskasing, Nipigon and North Bay projects in the Canada segment, San Diego Gas & Electric purchases electricity from the Naval Station, NTC, and North Island projects in the West U.S. segment, Georgia Power Company purchases electricity from the Piedmont project in the East U.S. segment, and BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the Canada segment.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

13. Guarantees and Contingencies

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, 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.

Contingencies

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 which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of September 30, 2017.

OEFC Settlement

On January 19, 2017, the Supreme Court of Canada denied the OEFC leave to appeal the Ontario Court of Appeal Decision concerning the interpretation of the price escalator for power sold to the OEFC under certain PPAs with non-utility generators. We were not party to that litigation. We did, however, enter into a standstill agreement with the OEFC in April 2015, with respect to our North Bay, Kapuskasing and Tunis projects, arising out of our disagreement with the OEFC over the interpretation of the price escalator calculation in our PPAs. Under the standstill agreement we reserved our right to bring claims against the OEFC and suspended the running of any applicable limitation period to bring such claims.

On April 27, 2017, we entered into a settlement agreement with the OEFC with respect to our standstill agreement. Under the terms of the settlement, the OEFC has agreed to pay us approximately Cdn$36.4 million, representing the application of the price escalator calculation under the respective PPAs for power sold to the OEFC beginning in April 2013 and through December 31, 2017. A subsequent adjustment increased the total to approximately Cdn$37.8 million.

Of the Cdn$37.8 million amount agreed upon in settlement, we have received Cdn$34.0 million (approximately $25.6 million) and recorded it as other revenue in the second and third quarters of 2017, the periods when all contingencies were resolved. The remaining Cdn $3.8 million of the settlement relates to the application of the price escalator to the enhanced dispatch contracts at North Bay and Kapuskasing and will be recognized as revenue, when earned, through the expiration date of December 31, 2017.

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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 strategy to increase our intrinsic value on a per-share basis through disciplined management of our balance sheet and cost structure and investment of our discretionary cash in a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity securities ;

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

our ability to meet the financial covenants under our senior secured term loans 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, 2016 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, 2016 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:

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

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

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;

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our indebtedness and financing arrangements and the terms, covenants and restrictions included in our senior secured term loans;

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 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; and

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

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 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

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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.

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 PPAs, which seek to minimize exposure to changes in commodity prices. As of September 30, 2017, our power generation projects had an aggregate gross electric generation capacity of approximately 2,138 MW in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in twenty-three power generation projects across nine states in the United States and two provinces in Canada. Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis. The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence before June 2019. Eighteen of our projects are majority‑owned.

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. Nine of our projects, representing 25% of our net MW and 30% of our 2016 Project Adjusted EBITDA, have PPAs or other contractual arrangements that will expire within the next five years. These projects are Kapuskasing (2017), North Bay (2017), Williams Lake (2018), Kenilworth (2018), Naval Station (2019), NTC (2019), North Island (2019), Calstock (2020) and Oxnard (2020). There are no PPA expirations in 2021. See Recent Developments – Impairments below for further discussion of Naval Station, NTC and North Island. When a PPA expires, 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. Our MW-weighted average remaining PPA life is approximately 7 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

Senior secured term loan facility repricing

On October 18, 2017, the repricing of the $563 million senior secured term loan and senior secured revolving credit facility became effective. On October 30, 2017, the extension of our $200 million senior secured revolving credit facility also became effective. As a result of the repricing, the interest rate margin on the term loan and revolver was

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reduced by an additional 0.75% to LIBOR plus 3.50%. The senior secured revolving credit facility was extended one year through April 13, 2022. The senior secured term loan and revolving credit facility were previously repriced in April 2017, reducing the interest rate from LIBOR plus 5.00% to LIBOR plus 4.25%.The LIBOR floor remains at 1.00% and the mandatory 1% annual amortization and cash sweep provisions of the term loan are unchanged.

Piedmont term loan repayment

Credit upgrade

In October 2017, Moody’s Investors Service (“Moody’s) upgraded our Corporate Family Rating to Ba3 from B1 and the senior secured term loan and revolving credit facilities at APLP Holdings to Ba2 from Ba3.

San Diego impairments

We test our long-lived assets and goodwill for impairment at least annually, or more often if deemed

appropriate based on management’s determination of the occurrence of certain trigger events under our impairment

policy. When we have an expectation that we will be unable to renew or renegotiate a PPA, the value of the project may be impaired such that we would record an impairment loss.

The San Diego Projects sell power to SDG&E under PPAs that are scheduled to expire in December 2019. In addition, the three projects supply steam to the U.S. Navy under agreements that provide these projects with the right to use the property at the respective sites on which each project is located (the "Navy agreements"). The Navy agreements are scheduled to expire in February 2018. In August 2017, we were unsuccessful in obtaining contracts to provide the Navy energy security and resilience that would have provided us with the right to use the Naval Station and North Island sites beyond February 2018. Although we are pursuing alternative paths to maintaining rights to the sites, if not successful, the plants may cease to operate as early as February 2018.

Following notification of the outcome of the Navy solicitation, we determined that it was a triggering event to test the long-lived assets at the San Diego projects for impairment. We performed this test at each of these projects as of July 31, 2017. As a result, we recorded a total $57.3 million impairment ($22.5 million at Naval Station, $13.5 million at NTC and $21.2 million at North Island) in the three and nine months ended September 30, 2017. The San Diego projects have net removal obligations recorded of $4.6 million at September 30, 2017. We are in the process of evaluating the estimated removal costs and may have further adjustments to this amount in the three months ended December 31, 2017 as the timing and final arrangements for decommissioning the sites have not been determined.

Subsequent to recording the impairment, we will also accelerate amortization through February 2018 of the remaining property, plant and equipment with the three projects, totaling approximately $7.7 million. Both the accelerated amortization and the impairment are non-cash expenses that do not affect cash flow, nor are they included in Project Adjusted EBITDA.

Additionally, in connection with the potential early termination of the PPAs, we could be liable for liquidated damages under the PPAs. However, we believe that we will not be required to pay any liquidated damages associated with the early termination of the PPAs, because we believe that the circumstances of the termination and the agreements in place between us and the PPA counterparty relieve us of potential liabilities.

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OUR POWER PROJECTS

The table below outlines our portfolio of power generating assets in operation as of November 7, 2017, 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 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.

Power

Customer Credit

Project

Location

Type

Economic Interest

Net MW

Primary Electric Purchasers

Contract Expiry

Rating (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

September 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

June 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

New York

Hydro

100.00

Niagara Mohawk Power Corporation

December 2027 (4)

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

November 2019 (5)

Naval Training Center

California

Natural Gas

100.00

San Diego Gas & Electric

November 2019 (5)

North Island

California

Natural Gas

100.00

San Diego Gas & Electric

November 2019 (5)

Oxnard

California

Natural Gas

100.00

Southern California Edison

April 2020

BBB+

Manchief

Colorado

Natural Gas

300

100.00

300

Public Service Company of Colorado

April 2022 (6)

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

March 2037

BBB

Canada Segment

Mamquam

British Columbia

Hydro

100.00

British Columbia Hydro and Power Authority

September 2027 (7)

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

Ontario Electricity Financial Corporation

June 2020

Kapuskasing

Ontario

Natural Gas

100.00

Ontario Electricity Financial Corporation

December 2017 (8)

Nipigon

Ontario

Natural Gas

100.00

Ontario Electricity Financial Corporation

December 2022 (9)

North Bay

Ontario

Natural Gas

100.00

Ontario Electricity Financial Corporation

December 2017 (8)

Tunis

Ontario

Natural Gas

100.00

Independent Electricity System Operator

(10)

⁽¹⁾

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

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⁽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.

⁽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 September 30, 2017, the facility has generated 7,246 GWh under its PPA. Based on cumulative generation to date, we expect the PPA to expire prior to December 2027.

⁽⁵⁾

Our land use license agreements with the U.S. Navy expire on February 8, 2018. Our PPAs with SDG&E expire on December 1, 2019. See Recent Developments – Impairments for additional information on these PPAs.

⁽⁶⁾

Public Service Company of Colorado has options to purchase Manchief in either May 2020 or May 2021.

⁽⁷⁾

BC Hydro has the option to purchase Mamquam in November 2021 and every five years thereafter.

⁽⁸⁾

In December 2016, we entered into agreements to terminate our PPAs originally scheduled to expire on December 31, 2017 one year ahead of their expiration dates. Additionally, we entered into enhanced dispatch contracts with the IESO, which provide a fixed monthly payment to the plants until December 31, 2017. The contracts have no delivery obligations and allow us to retain operating flexibility. Based on our assessment of the Ontario power market, including the estimated impact on plant economics, we do not expect to operate the plants during the term of the enhanced dispatch contracts or subsequent to their expiration.

⁽⁹⁾

In December 2016, we entered into an enhanced dispatch contract with IESO. The enhanced dispatch contract for Nipigon provides fixed monthly payments to that plant through October 31, 2018. During that period, the plant's PPA with the OEFC will be suspended. At the conclusion of that period, the arrangement will revert to the existing terms of the PPA, which is scheduled to expire in December 2022. We do not expect Nipigon to be operational through October 31, 2018.

⁽¹⁰⁾

In December 2014, we entered into an agreement with the Ontario Power Authority and its successor, the IESO for the future operations of the Tunis facility. Subject to meeting certain technical requirements, Tunis will operate under a 15-year agreement with the IESO commencing before June 2019. 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 operates.

Consolidated Overview and Results of Operations

Performance highlights

The following table provides a summary of our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, which are analyzed in greater detail below:



	Three months ended				Nine months ended
	September 30,				September 30,
	2017		2016		2017		2016
Project revenue	$	108.6	$	101.2	$	331.0	$	305.8
Project loss	$	(20.9)	$	(57.1)	$	(7.7)	$	(3.3)
Net loss attributable to Atlantic Power Corporation	$	(32.9)	$	(82.4)	$	(57.5)	$	(116.2)
Loss per share attributable to Atlantic Power Corporation—basic and diluted	$	(0.29)	$	(0.69)	$	(0.50)	$	(0.96)
Project Adjusted EBITDA (1)	$	77.4	$	51.3	$	226.6	$	159.9

⁽¹⁾

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

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Revenue increased by $7.4 million from $101.2 million in the three months ended September 30, 2016 to $108.6 million in the three months ended September 30, 2017. The primary drivers of the increase are as follows:

Hydrological conditions – a $4.7 million increase in revenue from higher water flows at our hydro projects; and

Morris – a $4.3 million increase in revenue at our Morris project, which underwent a turbine overhaul in the comparable 2016 period.

These increases in project revenue were partially offset by:

Enhanced dispatch contracts – under the enhanced dispatch contracts with the IESO, we suspended operations at our Kapuskasing, North Bay and Nipigon projects, which resulted in approximately $4.2 million of lower revenue than the comparable 2016 period.

Consolidated project loss decreased by $36.2 million from $57.1 million of project loss in the three months ended September 30, 2016 to $20.9 million project loss in the three months ended September 30, 2017. The primary drivers of the decrease are as follows:

Revenue – revenue increased by $7.4 million as discussed above;

Fuel expense – fuel expense decreased $11.8 million from the comparable 2016 period primarily due to the expiration of fuel contracts at North Bay and Kapuskasing on December 31, 2016, a $1.1 million decrease related to favorable fuel swap settlements at our Orlando project and a $1.7 million decrease at Nipigon, which is currently not in operation under the terms of its enhanced dispatch contract. This was partially offset by $3.3 million of higher fuel expense at Morris, which underwent a turbine overhaul in the comparable 2016 period;

Operations and maintenance – operations and maintenance expense decreased $8.4 million from the comparable 2016 period primarily due to a $6.5 million decrease at our Morris project, which underwent a turbine overhaul in August 2016; and

Impairment – we recorded $57.3 million of long-lived asset impairments at Naval Station, NTC and North Island in August 2017. We recorded $84.7 million of goodwill and long-lived asset impairments in the comparable period in 2016.

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

Depreciation and amortization – depreciation expense increased $6.1 million from the comparable 2016 period due to the acceleration of depreciation at North Bay and Kapuskasing through December 2017, the expiration date of the plants’ enhanced dispatch contracts; and

Fuel swap and natural gas purchase agreements – the change in fair value of our derivative instruments decreased $10.9 million from the comparable 2016 period.

Revenue increased by $25.2 million from $305.8 million in the nine months ended September 30, 2016 to $331.0 million in the nine months ended September 30, 2017. The primary drivers of the increase are as follows:

OEFC settlement – we recorded approximately $25.6 million of revenue at North Bay, Kapuskasing and Tunis related to our settlement agreement entered into with the OEFC in April 2017 arising out of our disagreement over the interpretation of the price escalator calculation in our PPAs at these projects;

Hydrological conditions – an $8.1 million increase in revenue from higher water flows at our hydro projects, primarily at Curtis Palmer;

San Diego projects – a $6.7 million increase in revenue at our San Diego projects, primarily due to higher steam revenue than the comparable 2016 period; and

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Morris – a $1.6 million increase in revenue at our Morris project, which underwent a turbine overhaul in the comparable 2016 period.

These increases in project revenue were partially offset by:

Enhanced dispatch contracts – under the enhanced dispatch contracts with the IESO, we suspended operations at our Kapuskasing, North Bay and Nipigon projects, which resulted in approximately $16.6 million of lower revenue than the comparable 2016 period.

Consolidated project loss increased by $4.4 million from $3.3 million of project loss in the nine months ended September 30, 2016 to $7.7 million of project loss in the nine months ended September 30, 2017. The primary drivers of the increase are as follows:

Impairment – we recorded $57.3 million of impairments at our wholly-owned Naval Station, Naval Training Center and North Island projects, and $57.7 million of impairments at our Chambers and Selkirk projects, which are accounted under the equity method of accounting in the nine months ended September 30, 2017. This was partially offset by $84.7 million of goodwill and long-lived asset impairments recorded in the comparable 2016 period at our Mamquam, Curtis Palmer, North Bay and Kapuskasing projects;

Fuel swap and natural gas purchase agreements – the change in fair value of our derivative instruments decreased $25.8 million from the comparable 2016 period; and

Depreciation and amortization – depreciation expense increased $14.9 million from the comparable 2016 period primarily due to the acceleration of depreciation at North Bay and Kapuskasing through December 2017, the expiration date of the plants’ enhanced dispatch contracts.

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

Revenue – revenue increased by $25.2 million as discussed above;

Fuel expense – fuel expense decreased $31.7 million from the comparable 2016 period primarily due to the $34.4 million impact of the expiration of fuel contracts at North Bay and Kapuskasing on December 31, 2016, a $5.6 million decrease related to favorable fuel swap settlements at our Orlando project and a $4.8 million decrease at Nipigon, which is currently not in operation under the terms of its enhanced dispatch contract. This was partially offset by $6.5 million of higher fuel expense at Morris, which underwent a turbine overhaul in the comparable 2016 period, and $6.1 million of higher fuel expense at our San Diego projects due to higher fuel prices; and

Operations and maintenance – operations and maintenance expense decreased $16.0 million from the comparable 2016 period primarily due to a $7.3 million decrease at our Morris project, which underwent a turbine overhaul in August 2016, and a $4.7 million decrease at Kapuskasing and North Bay, which do not operate under the term of their enhanced dispatch contracts.

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. 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 September 30, 2017 compared to the three months ended September 30, 2016

The following table provides our consolidated results of operations:


	Three months ended September 30,
	2017		2016		$ change		% change
Project revenue:
Energy sales	$	36.5	$	40.7	$	(4.2)	(10.3)	%
Energy capacity revenue		37.9		44.0		(6.1)	(13.9)	%
Other		34.2		16.5		17.7	107.3	%
		108.6		101.2		7.4	7.3	%
Project expenses:
Fuel		26.2		36.8		(10.6)	(28.8)	%
Operations and maintenance		19.8		28.2		(8.4)	(29.8)	%
Depreciation and amortization		31.4		25.3		6.1	24.1	%
		77.4		90.3		(12.9)	(14.3)	%
Project other expense:
Change in fair value of derivative instruments		(1.9)		9.0		(10.9)	(121.1)	%
Equity in earnings of unconsolidated affiliates		9.2		9.6		(0.4)	NM
Interest expense, net		(2.2)		(2.4)		0.2	NM
Impairment		(57.3)		(84.7)		27.4	(32.3)	%
Other income, net		0.1		0.5		(0.4)	(80.0)	%
		(52.1)		(68.0)		15.9	NM
Project loss		(20.9)		(57.1)		36.2	(63.4)	%
Administrative and other expenses:
Administration		5.5		5.7		(0.2)	NM
Interest expense, net		13.8		20.0		(6.2)	(31.0)	%
Foreign exchange loss (gain)		9.4		(3.4)		12.8	(376.5)	%
Other income, net		—		(1.7)		1.7	(100.0)	%
		28.7		20.6		8.1	39.3	%
Loss from operations before income taxes		(49.6)		(77.7)		28.1	(36.2)	%
Income tax (benefit) expense		(15.9)		2.6		(18.5)	NM
Net loss		(33.7)		(80.3)		46.6	(58.0)	%
Net (loss) income attributable to Preferred share dividends of a subsidiary company		(0.8)		2.1		(2.9)	(138.1)	%
Net loss attributable to Atlantic Power Corporation	$	(32.9)	$	(82.4)	$	49.5	(60.1)	%

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The following tables provide our project income by segment:


	Three months ended September 30, 2017
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	20.1	$	8.4	$	8.0	$	—	$	36.5
Energy capacity revenue		16.3		19.0		2.6		—		37.9
Other		3.4		7.7		22.9		0.2		34.2
		39.8		35.1		33.5		0.2		108.6
Project expenses:
Fuel		11.6		11.4		3.2		—		26.2
Operations and maintenance		8.7		5.6		5.7		(0.2)		19.8
Depreciation and amortization		9.1		8.1		14.1		0.1		31.4
		29.4		25.1		23.0		(0.1)		77.4
Project other income (expense):
Change in fair value of derivative instruments		(1.3)		—		(1.2)		0.6		(1.9)
Equity in earnings of unconsolidated affiliates		8.1		1.1		—		—		9.2
Interest expense, net		(2.2)		—		—		—		(2.2)
Impairment		—		(57.3)		—		—		(57.3)
Other income, net		—		—		0.1		—		0.1
		4.6		(56.2)		(1.1)		0.6		(52.1)
Project income (loss)	$	15.0	$	(46.2)	$	9.4	$	0.9	$	(20.9)


	Three months ended September 30, 2016
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	13.9	$	9.5	$	17.3	$	—	$	40.7
Energy capacity revenue		15.0		19.0		10.0		—		44.0
Other		2.4		5.6		8.3		0.2		16.5
		31.3		34.1		35.6		0.2		101.2
Project expenses:
Fuel		9.6		10.5		16.7		—		36.8
Operations and maintenance		14.2		5.5		8.2		0.3		28.2
Depreciation and amortization		8.5		7.3		9.4		0.1		25.3
		32.3		23.3		34.3		0.4		90.3
Project other income (expense):
Change in fair value of derivative instruments		1.2		—		5.6		2.2		9.0
Equity in earnings of unconsolidated affiliates		9.0		0.6		—		—		9.6
Interest expense, net		(2.4)		—		—		—		(2.4)
Impairment		(15.4)		—		(69.3)		—		(84.7)
Other income, net		—		—		—		0.5		0.5
		(7.6)		0.6		(63.7)		2.7		(68.0)
Project (loss) income	$	(8.6)	$	11.4	$	(62.4)	$	2.5	$	(57.1)

East U.S.

Project income was $15.0 million for the three months ended September 30, 2017, an increase of $23.6 million from a project loss of $8.6 million in the comparable 2016 period primarily due to:

increased project income of $18.9 million at Curtis Palmer primarily due to a $15.4 million goodwill impairment charge recorded in the three months ended September 30, 2016 and $3.7 million of increased revenues due to higher water flows than the comparable 2016 period; and

increased project income of $6.7 million at Morris primarily due to $6.5 million of decreased maintenance expense resulting from the overhaul of two gas turbines and one steam turbine in August 2016, as well as replacement of a continuous emissions monitoring system.

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These increases were partially offset by:

decreased project income of $1.5 million at Piedmont primarily due to a negative $1.8 million change in fair value of interest rate swap agreements.

West U.S.

Project loss was $46.2 million for the three months ended September 30, 2017, a decrease of $57.6 million from project income of $11.4 million in the comparable 2016 period primarily due to:

decreased project income of $20.2 million, $19.1 million and $12.4 million at Naval Station, North Island and NTC primarily due to $22.5 million, $21.2 million and $13.5 million long-lived asset impairments recorded for the three months ended September 30, 2017, respectively.

Canada

Project income was $9.4 million for the three months ended September 30, 2017, an increase of $71.8 million from a project loss of $62.4 million in the comparable 2016 period primarily due to:

increased project income of $51.3 million at Mamquam primarily due to a $50.2 million goodwill impairment charge recorded in the comparable period in 2016 and $0.8 million increased revenue from higher water flows than the comparable 2016 period;

increased project income of $10.1 million at North Bay primarily due to $10.2 million of goodwill and long-lived asset impairments recorded in the comparable 2016 period; and

increased project income of $7.9 million at Kapuskasing primarily due to $8.9 million of goodwill and long-lived asset impairments recorded in the comparable 2016 period, $6.0 million of lower fuel expense due to the expiration of fuel purchase agreements in December 2016, as well as the plant not being operational due to the enhanced dispatch agreements. These increases were partially offset by a positive $3.4 million change in the fair value of gas purchase agreements that expired in December 2016 and were accounted for as derivatives, $2.6 million of accelerated depreciation in the three months ended September 20, 2017 and $1.0 million decreased revenue due to the plant not being operational under the enhanced dispatch agreement.

Un‑allocated Corporate

Project income for the three months ended September 30, 2017 of $0.9 million decreased from a project income of $2.5 million in the comparable 2016 period primarily due to a $1.6 million decrease in the fair value of interest swaps accounted for as derivatives.

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 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 did not change materially from the 2016 comparable period.

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Interest expense, net

Interest expense decreased $6.2 million from the comparable 2016 period primarily due to lower outstanding debt balances at September 30, 2017 than the comparable 2016 period, as well as a lower interest rate on our senior secured credit facility.

Foreign exchange loss

Foreign exchange loss was $9.4 million for the three months ended September 30, 2017, a decrease of $12.8 million from a $3.4 million foreign exchange gain in the comparable 2016 period, primarily due to an $11.8 million increase in unrealized loss from the revaluation of instruments denominated in Canadian dollars. The closing U.S. dollar to Canadian dollar exchange rates were 1.25 and 1.31 at September 30, 2017 and 2016, respectively, a decrease of 3.8% during the three months ended September 30, 2017, as compared to a decrease of 1.5% in the comparable 2016 period. The average U.S. dollar to Canadian dollar exchange rates were 1.25 and 1.31 for the three months ended September 30, 2017 and 2016, respectively.

Other income, net

Other income, net decreased $1.7 million primarily due to a gain recorded on the purchase and cancellation of convertible debentures in the comparable 2016 period.

Income tax expense

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primarily of increases of $9.3 million in Canada related to capital loss on intercompany notes, $1.9 million relating to operating in higher tax rate jurisdictions and $0.8 million of other permanent differences.

Nine months ended September 30, 2017 compared to the nine months ended September 30, 2016

The following table provides our consolidated results of operations:


	Nine months ended September 30,
	2017		2016		$ change		% change
Project revenue:
Energy sales	$	113.6	$	138.4	$	(24.8)	(17.9)	%
Energy capacity revenue		85.7		113.2		(27.5)	(24.3)	%
Other		131.7		54.2		77.5	143.0	%
		331.0		305.8		25.2	8.2	%
Project expenses:
Fuel		79.1		110.8		(31.7)	(28.6)	%
Operations and maintenance		63.4		79.4		(16.0)	(20.2)	%
Depreciation and amortization		90.5		75.6		14.9	19.7	%
		233.0		265.8		(32.8)	(12.3)	%
Project other expense:
Change in fair value of derivative instruments		(5.8)		20.0		(25.8)	(129.0)	%
Equity in (loss) earnings of unconsolidated affiliates		(36.1)		27.9		(64.0)	(229.4)	%
Interest expense, net		(6.6)		(6.9)		0.3	(4.3)	%
Impairment		(57.3)		(84.7)		27.4	(32.3)	%
Other income, net		0.1		0.4		(0.3)	(75.0)	%
		(105.7)		(43.3)		(62.4)	NM
Project loss		(7.7)		(3.3)		(4.4)	133.3	%
Administrative and other expenses (income):
Administration		17.6		17.6		—	NM
Interest expense, net		49.5		87.9		(38.4)	(43.7)	%
Foreign exchange loss		17.7		19.1		(1.4)	(7.3)	%
Other income, net		—		(3.9)		3.9	(100.0)	%
		84.8		120.7		(35.9)	(29.7)	%
Loss from continuing operations before income taxes		(92.5)		(124.0)		31.5	(25.4)	%
Income tax benefit		(38.5)		(14.2)		(24.3)	171.1	%
Net loss		(54.0)		(109.8)		55.8	NM
Net income attributable to Preferred share dividends of a subsidiary company		3.5		6.4		(2.9)	(45.3)	%
Net loss attributable to Atlantic Power Corporation	$	(57.5)	$	(116.2)	$	58.7	NM

The following tables provide our project income by segment:

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	Nine months ended September 30, 2017
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	66.3	$	24.6	$	22.7	$	—	$	113.6
Energy capacity revenue		38.8		38.9		8.0		—		85.7
Other		11.2		22.7		97.1		0.7		131.7
		116.3		86.2		127.8		0.7		331.0
Project expenses:
Fuel		34.8		33.5		10.8		—		79.1
Operations and maintenance		25.2		18.9		19.5		(0.2)		63.4
Depreciation and amortization		26.9		22.7		40.6		0.3		90.5
		86.9		75.1		70.9		0.1		233.0
Project other income (expense):
Change in fair value of derivative instruments		(3.3)		—		(5.4)		2.9		(5.8)
Equity in loss of unconsolidated affiliates		(35.9)		(0.2)		—		—		(36.1)
Interest expense, net		(6.6)		—		—		—		(6.6)
Impairment		—		(57.3)		—		—		(57.3)
Other income, net		—		—		0.1		—		0.1
		(45.8)		(57.5)		(5.3)		2.9		(105.7)
Project (loss) income	$	(16.4)	$	(46.4)	$	51.6	$	3.5	$	(7.7)


	Nine months ended September 30, 2016
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	53.8	$	23.6	$	61.0	$	—	$	138.4
Energy capacity revenue		39.8		38.9		34.5		—		113.2
Other		10.7		16.2		26.5		0.8		54.2
		104.3		78.7		122.0		0.8		305.8
Project expenses:
Fuel		35.4		26.4		49.0		—		110.8
Operations and maintenance		33.2		18.5		26.6		1.1		79.4
Depreciation and amortization		25.5		21.9		27.8		0.4		75.6
		94.1		66.8		103.4		1.5		265.8
Project other income (expense):
Change in fair value of derivative instruments		3.0		—		17.6		(0.6)		20.0
Equity in earnings of unconsolidated affiliates		26.0		1.9		—		—		27.9
Interest expense, net		(6.9)		—		—		—		(6.9)
Impairment		(15.4)		—		(69.3)		—		(84.7)
Other income, net		—		—		—		0.4		0.4
		6.7		1.9		(51.7)		(0.2)		(43.3)
Project income (loss)	$	16.9	$	13.8	$	(33.1)	$	(0.9)	$	(3.3)

East U.S.

Project loss was $16.4 million for the nine months ended September 30, 2017, a decrease of $33.3 million from project income of $16.9 million in the comparable 2016 period primarily due to:

decreased project income of $47.7 million and $11.5 million at Chambers and Selkirk, respectively, primarily due to impairments of $47.1 million and $10.6 million recorded in the nine months ended September 30, 2017; and

decreased project income of $6.8 million at Orlando primarily due to a $9.6 million decrease in the change in fair value of derivatives and a maintenance outage, partially offset by lower fuel expense resulting from

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the settlement of favorable fuel swaps.

These decreases were partially offset by:

increased project income of $25.4 million at Curtis Palmer primarily due to a $15.4 million goodwill impairment charge recorded in the nine months ended September 30, 2016 and $10.0 million in increased revenues due to higher water flows than the comparable 2016 period.

West U.S.

Project loss was $46.4 million for the nine months ended September 30, 2017, a decrease of $60.2 million from project income of $13.8 million in the comparable 2016 period primarily due to:

decreased project income of $19.3 million, $17.8 million and $11.9 million at Naval Station, North Island and NTC primarily due to $22.5 million, $21.2 million and $13.5 million long-lived asset impairments recorded for the nine months ended September 30, 2017, respectively.

Canada

Project income of $51.6 million for the nine months ended September 30, 2017, an increase of $84.7 million from project loss of $33.1 million in the comparable 2016 period primarily due to:

increased project income of $47.7 million at Mamquam primarily due to a $50.2 million goodwill impairment charge recorded in the comparable period in 2016, offset by $1.9 million decrease due to lower water flows and a forced maintenance outage that occurred in the second quarter of 2017;

increased project income of $16.7 million at North Bay due to $9.0 million received from the OEFC settlement, $17.2 million of lower fuel expense due to the expiration of a fuel purchase agreement in December 2016 and $1.9 million of lower maintenance expense as a result of the plant not being operational due to its enhanced dispatch contract and $10.3 million of long-lived asset and goodwill impairment recorded in the comparable 2016 period. This was partially offset by a negative $10.3 million change in the fair value of a gas purchase agreement that expired in December 2016 and was accounted for as a derivative and $5.3 million of accelerated depreciation in the nine months ended September 30, 2017;

increased project income of $14.9 million at Kapuskasing due to $9.5 million received from the OEFC settlement, $17.2 million of lower fuel expense due to the expiration of a fuel purchase agreement in December 2016, $2.7 million of lower maintenance expense as a result of the plant not being operational due to its enhanced dispatch contract and $8.9 million of long-lived asset and goodwill impairment recorded in the comparable 2016 period. This was partially offset by a negative $10.3 million change in the fair value of gas purchase agreement that expired in December 2016 and was accounted for as a derivative and $7.3 million of accelerated depreciation in the nine months ended September 30, 2017; and

increased project income at Tunis due to $6.7 million received from the OEFC settlement.

Un‑allocated Corporate

Total project income for the nine months ended September 30, 2017 was $3.5 million compared to a total project loss of $0.9 million in the comparable 2016 period. The change was primarily due to a $3.5 million increase in the fair value of interest swaps accounted for as derivatives.

Administrative and other expenses (income)

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potentially significant fluctuations include the non‑cash impact of foreign exchange fluctuations from period to period on 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 did not change materially from the 2016 comparable period.

Interest expense, net

Interest expense decreased $38.4 million from the comparable 2016 period primarily due to the write-off of $30.2 million of deferred financing costs related to the senior secured credit facilities and repurchase and cancellation of convertible debentures during the nine months ended September 30, 2016, as well as lower outstanding debt balances and a lower interest rate on the senior secured credit facilities at September 30, 2017.

Foreign exchange loss

Foreign exchange loss for the nine months ended September 30, 2017 decreased $1.4 million from the comparable 2016 period primarily due to a $2.8 million decrease in unrealized loss in the revaluation of instruments denominated in Canadian dollars. The repurchase and cancellation of Cdn$152.1 million Canadian dollar-denominated convertible debentures during the nine months ended September 30, 2016 was the most significant factor in the decrease. The closing U.S. dollar to Canadian dollar exchange rates were 1.25 and 1.31 at September 30, 2017 and 2016, respectively, a decrease of 7.0% during the nine months ended September 30, 2017, as compared to a decrease of 5.2% in the comparable 2016 period. The average U.S. dollar to Canadian dollar exchange rates were 1.30 and 1.34 for the nine months ended September 30, 2017 and 2016, respectively.

Other income, net

Other income, net decreased $3.9 million primarily due to a gain recorded on the purchase and cancellation of convertible debentures in the comparable 2016 period.

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 (“MWh”). 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 nine months ended September 30, 2017. The terms of our PPAs provide for certain levels of planned and unplanned outages. All references below are denominated in net Gigawatt-hours (“net GWh”).


	Generation
	Three months ended September 30,
			% change
(in Net GWh)	2017	2016	2017 vs. 2016
Segment
East U.S.	662.7	557.0	19.0	%
West U.S.	534.6	522.9	2.2	%
Canada	239.7	443.7	(46.0)	%
Total	1,437.0	1,523.6	(5.7)	%

Three months ended September 30, 2017 compared with three months ended September 30, 2016

Aggregate power generation for the three months ended September 30, 2017 decreased 5.7% from the comparable 2016 period primarily due to:

decreased generation in the Canada segment primarily due to a decrease of 217.8 net GWh on a combined basis at Kapuskasing, Nipigon and North Bay, due to their suspended operation status under the enhanced dispatch contracts.

These decreases were partially offset by:

increased generation in the East U.S. segment primarily due to a 105.3 net GWh increase in generation at Morris due to a maintenance outage in the comparable period in 2016 and a 31.3 net GWh increase in generation at Curtis Palmer due to higher water flows than the comparable period in 2016.


	Generation
	Nine months ended September 30,
			% change
(in Net GWh)	2017	2016	2017 vs. 2016
Segment
East U.S.	1,866.2	1,835.7	1.7	%
West U.S.	1,155.7	1,225.6	(5.7)	%
Canada	698.2	1,488.5	(53.1)	%
Total	3,720.1	4,549.8	(18.2)	%

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Aggregate power generation for the nine months ended September 30, 2017 decreased 18.2% from the comparable 2016 period primarily due to:

decreased generation in the Canada segment primarily due to a decrease of 702.0 net GWh on a combined basis at Kapuskasing, Nipigon and North Bay, due to their suspended operation status under the enhanced dispatch contracts, and a 60.1 net GWh decrease in generation at Mamquam due to lower water flows and a maintenance outage in the three months ended September 30, 2017; and

decreased generation in the West U.S. segment primarily due to a 101.5 net GWh decrease in generation at Frederickson due to lower merchant dispatch, offset by a 36.8 net GWh increase in generation at Manchief

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due to higher dispatch than the comparable period in 2016.

These decreases were partially offset by:

increased generation in the East U.S. segment primarily due to a 79.6 net GWh increase in generation at Curtis Palmer due to higher water flows than the comparable period in 2016 and a 51.7 net GWh increase in generation at Morris due to a maintenance outage in the comparable period in 2016.


	Availability
	Three months ended September 30,
					% change
	2017		2016		2017 vs. 2016
Segment
East U.S.	99.3	%	88.2	%	12.6	%
West U.S.	97.1	%	96.9	%	0.2	%
Canada	97.5	%	90.6	%	7.6	%
Weighted average	98.4	%	91.1	%	8.0	%

Three months ended September 30, 2017 compared with three months ended September 30, 2016

Aggregate power availability for the three months ended September 30, 2017 increased 8.0% from the comparable 2016 period primarily due to:

increased availability in the East U.S. segment primarily due to a maintenance outage at Morris in the comparable period in 2016; and

increased availability in the Canada segment primarily due to a maintenance outage at Mamquam in the comparable period in 2016.


	Availability
	Nine months ended September 30,
					% change
	2017		2016		2017 vs. 2016
Segment
East U.S.	94.3	%	93.3	%	1.1	%
West U.S.	90.5	%	92.4	%	(2.1)	%
Canada	91.8	%	95.5	%	(3.9)	%
Weighted average	92.9	%	93.5	%	(0.6)	%

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Aggregate power availability for the nine months ended September 30, 2017 decreased 0.6% from the comparable 2016 period primarily due to:

decreased availability in the West U.S. segment primarily due to a maintenance outage at Frederickson; and

decreased availability in the Canada segment primarily due to maintenance outages at Williams Lake and Mamquam.

These decreases were partially offset by:

increased availability in the East U.S. segment primarily due to a longer planned maintenance outage in the comparable period in 2016 at Morris.

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

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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						Nine months ended
	September 30,				$ change		September 30,				$ change
	2017		2016		2017 vs 2016		2017		2016		2017 vs 2016
Net loss	$	(33.7)	$	(80.3)	$	46.6	$	(54.0)	$	(109.8)	$	55.8
Income tax (benefit) expense		(15.9)		2.6		(18.5)		(38.5)		(14.2)		(24.3)
Loss from operations before income taxes		(49.6)		(77.7)		28.1		(92.5)		(124.0)		31.5
Administration		5.5		5.7		(0.2)		17.6		17.6		—
Interest expense, net		13.8		20.0		(6.2)		49.5		87.9		(38.4)
Foreign exchange loss (gain)		9.4		(3.4)		12.8		17.7		19.1		(1.4)
Other income, net		—		(1.7)		1.7		—		(3.9)		3.9
Project loss	$	(20.9)	$	(57.1)	$	36.2	$	(7.7)	$	(3.3)	$	(4.4)
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization		36.6		30.4		6.2		105.6		90.8		14.8
Interest expense, net		2.5		2.8		(0.3)		8.0		8.2		(0.2)
Change in the fair value of derivative instruments		2.0		(9.0)		11.0		5.8		(20.1)		25.9
Other (income) expense		(0.1)		(0.5)		0.4		57.6		(0.4)		58.0
Impairment		57.3		84.7		(27.4)		57.3		84.7		(27.4)
Project Adjusted EBITDA	$	77.4	$	51.3	$	26.1	$	226.6	$	159.9	$	66.7
Project Adjusted EBITDA by segment
East U.S.		30.6		19.4		11.2		86.8		70.5		16.3
West U.S.		21.7		21.3		0.4		41.5		43.4		(1.9)
Canada		24.6		10.7		13.9		97.3		46.2		51.1
Un-Allocated Corporate		0.5		(0.1)		0.6		1.0		(0.2)		1.2
Total		77.4		51.3		26.1		226.6		159.9		66.7

East U.S.

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


	Three months ended September 30,
					% change
	2017		2016		2017 vs. 2016
East U.S.
Project Adjusted EBITDA	$	30.6	$	19.4	58	%

Three months ended September 30, 2017 compared with three months ended September 30, 2016

Project Adjusted EBITDA for the three months ended September 30, 2017 increased $11.2 million from the comparable 2016 period primarily due to increased Project Adjusted EBITDA of:

$7.5 million at Morris due to decreased maintenance expense resulting from the overhaul of two gas turbines and one steam turbine in August 2016; and

$3.5 million at Curtis Palmer primarily due to higher water flows than the comparable 2016 period.

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	Nine months ended September 30,
					% change
	2017		2016		2017 vs. 2016
East U.S.
Project Adjusted EBITDA	$	86.8	$	70.5	23	%

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Project Adjusted EBITDA for the nine months ended September 30, 2017 increased $16.3 million from the comparable 2016 period primarily due to increased Project Adjusted EBITDA of:

$10.0 million at Curtis Palmer primarily due to higher water flows than the comparable 2016 period;

$2.8 million at Orlando primarily due to lower fuel expense resulting from the settlement of favorable fuel swaps;

$2.4 million at Morris primarily due to the overhaul of two gas turbines and one steam turbine in August 2016; and

$2.1 million at Piedmont primarily due to the replacement of a superheater that occurred in the comparable 2016 period.

West U.S.

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


	Three months ended September 30,
					% change
	2017		2016		2017 vs 2016
West U.S.
Project Adjusted EBITDA	$	21.7	$	21.3	2	%

Three months ended September 30, 2017 compared with three months ended September 30, 2016

Project Adjusted EBITDA for the three months ended September 30, 2017 increased $0.4 million and did not change materially from the comparable 2016 period.


	Nine months ended September 30,
					% change
	2017		2016		2017 vs 2016
West U.S.
Project Adjusted EBITDA	$	41.5	$	43.4	(4)	%

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Project Adjusted EBITDA for the nine months ended September 30, 2017 decreased $1.9 million from the comparable 2016 period primarily due to decreased Project Adjusted EBITDA of:

$2.2 million at Frederickson primarily due to higher maintenance expense than the comparable 2016 period.

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Canada

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


	Three months ended September 30,
					% change
	2017		2016		2017 vs. 2016
Canada
Project Adjusted EBITDA	$	24.6	$	10.7	130	%

Three months ended September 30, 2017 compared with three months ended September 30, 2016

Project Adjusted EBITDA for the three months ended September 30, 2017 increased $13.9 million from the comparable 2016 period primarily due to increased Project Adjusted EBITDA of:

$10.3 million at Kapuskasing and North Bay, primarily due to an $11.8 million decrease in fuel expense, as a result of the expiration of fuel purchase agreements in December 2016 and their non-operational status under the terms of their enhanced dispatch contracts, partially offset by a $2.1 million decrease in revenue;

$1.1 million at Mamquam primarily due to higher water flows than the comparable 2016 period; and

$1.0 million at Williams Lake primarily due to fewer maintenance projects and higher availability than the comparable 2016 period.


	Nine months ended September 30,
					% change
	2017		2016		2017 vs. 2016
Canada
Project Adjusted EBITDA	$	97.3	$	46.2	111	%

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Project Adjusted EBITDA for the nine months ended September 30, 2017 increased $51.1 million from the comparable 2016 period primarily due to increased Project Adjusted EBITDA of:

$45.8 million at Kapuskasing and North Bay, primarily due to $18.5 million received from the OEFC settlement, a $22.9 million increase in gross margin and $4.7 million decrease in maintenance expense resulting from the expiration of fuel purchase agreements in December 2016 and their non-operational status under the terms of their enhanced dispatch contracts; and

$6.6 million at Tunis primarily due to the collection of the OEFC settlement.

These increases were partially offset by a decrease in Project Adjusted EBITDA of:

$2.5 million at Mamquam primarily due to a maintenance outage that occurred during the nine months ended September 30, 2017, as well as to lower water flows than the comparable 2016 period; and

$2.1 million at Calstock primarily due to lower waste heat revenue and higher fuel prices than the comparable 2016 period.

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Un‑allocated Corporate

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


	Three months ended September 30,
					% change
	2017		2016		2017 vs. 2016
Un-allocated Corporate
Project Adjusted EBITDA	$	0.5	$	(0.1)	NM

Three months ended September 30, 2017 compared with three months ended September 30, 2016

Project Adjusted EBITDA for the three months ended September 30, 2017 did not change materially from the comparable 2016 period.


	Nine months ended September 30,
					% change
	2017		2016		2017 vs. 2016
Un-allocated Corporate
Project Adjusted EBITDA	$	1.0	$	(0.2)	NM

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Project Adjusted EBITDA for the nine months ended September 30, 2017 did not change materially from the comparable 2016 period.

Liquidity and Capital Resources


	September 30,			December 31,
	2017			2016
Cash and cash equivalents	$	122.4	(1)	$	85.6
Restricted cash		12.5	(1)		13.3
Total		134.9			98.9
Revolving credit facility availability		127.4	(1)		118.5
Total liquidity	$	262.3		$	217.4

⁽¹⁾

In October 2017, we utilized $59.6 million of cash and $4.5 million of restricted cash in order to pay off, in full, $54.6 million of non-recourse debt, $0.1 million of accrued interest and $9.4 million of interest rate swap termination costs at our Piedmont project. Additionally, we reduced our outstanding letters of credit by $11.7 million resulting in revolving credit facility availability of $115.7 million.

Overview

Our primary sources of liquidity are 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 PPAs or we 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 service our debt obligations or implement our business plan, including financing external growth opportunities or fund our operations” in our Annual Report on Form 10‑K for the year ended December 31, 2016.

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We expect to reinvest approximately $39.7 million in our portfolio, including equity method investments, in the form of project capital expenditures and maintenance expenses in 2017, of which $28.5 million has been incurred through September 30, 2017. 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, 2016. We do not expect any other material or unusual requirements for cash outflows for 2017 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:


	Nine months ended
	September 30,
	2017		2016		Change
Net cash provided by operating activities	$	137.9	$	91.9	$	46.0
Net cash (used in) provided by investing activities		(4.9)		0.8		(5.7)
Net cash used in financing activities		(96.2)		(71.3)		(24.9)

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.

For the nine months ended September 30, 2017, the net increase in cash flows from operating activities of $46.0 million was primarily the result of the following:

OEFC Settlement – we received approximately $25.6 million related to our settlement with the OEFC in t he nine months ended September 30, 2017;

Impact of enhanced dispatch contracts and lower fuel costs in Ontario – we recorded $22.9 million of higher gross margin at North Bay, Kapuskasing and Nipigon as a result of the enhanced dispatch contracts in 2017, as well as the expiration of unfavorable gas purchase agreements in December 2016;

Operations and maintenance – we incurred $16.0 million of lower operations and maintenance costs, as a result of decreased maintenance expense at Morris and Williams Lake, which underwent outages in the comparable 2016 period, and at North Bay and Kapuskasing which did not operate during 2017 due to the terms of their enhanced dispatch contracts; and

Hydrological conditions at Curtis Palmer – higher water flows at our Curtis Palmer project had a $10.0 million impact on cash flows from operations.

These increases were partially offset by the following decreases to cash flows from operations:

Working capital – changes in working capital resulted in a $25.0 million decrease in cash flows from operating activities primarily due to $11.7 million of timing in revenue receipts at our Oxnard and Morris projects, $3.3 million of inventory buildup at our Manchief and Williams Lake projects in preparation for outages in 2018 and 2019, respectively, as well as other changes in timing of project and corporate receipts and payments;

Demand and fuel prices – higher maintenance expense at Frederickson as well as higher fuel prices resulted in a $2.2 million decrease in cash flows from operating activities from the comparable 2016 period;

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Hydrological conditions and maintenance outage at Mamquam – lower water flows and a forced outage at our Mamquam project had a $2.5 million impact on cash flows from operations; and

Waste heat – lower waste heat at our Calstock project had a $2.2 million impact on cash flows from operations.

Investing Activities

For the nine months ended September 30, 2017, the net decrease in cash flows used in investing activities of $5.7 million was primarily the result of the following:

Reimbursement of construction cost – we received a reimbursement of $4.7 million for the construction project at Morris in the comparable 2016 period; and

Restricted cash – the change in restricted cash decreased $1.8 million from the comparable 2016 period, primarily due to lower restricted cash requirements from decreased outstanding debt balances.

These decreases were partially offset by investments in capitalized plant additions that were $0.8 million lower in the nine months ended September 30, 2017 as compared to the comparable 2016 period.

Financing Activities

For the nine months ended September 30, 2017, the net decrease in cash flows from financing activities of $24.9 million was primarily the result of the following:

The Credit Facilities – we received $231.1 million of net proceeds from issuance of the senior secured term loan in the comparable 2016 period after repayment of the previous term loan;

Corporate and project-level debt repayments – we made $7.8 million of higher principal payments than the comparable 2016 period due to higher outstanding debt balances; and

Preferred share repurchases – we paid $3.1 million in the nine months ended September 30, 2017 to repurchase and cancel preferred shares.

These decreases were partially offset by the following increases to cash flows from financing activities:

Convertible debenture repayments – we paid $187.4 million to redeem and cancel convertible debentures in the comparable 2016 period;

Deferred financing costs – we incurred $16.2 million of deferred financing costs related to the refinancing of the senior secured credit facilities in the comparable 2016 period; and

Common share repurchases – we paid $0.2 million in the nine months ended September 30, 2017 to repurchase and cancel common shares as compared to $13.9 million in the comparable 2016 period.

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Corporate Debt

The following table summarizes the maturities of our corporate debt at September 30, 2017:


							Remaining
	Maturity	Interest					Principal
	Date	Rates					Repayments		2017		2018		2019		2020		2021		Thereafter
Senior secured term loan facility (1)(2)	April 2023	5.40	%	-	5.70	%	$	562.7	$	25.0	$	90.0	$	65.0	$	105.0	$	80.0	$	199.9
Atlantic Power Income LP Note	June 2036	5.95	%					168.3		—		—		—		—		—		168.3
Convertible Debenture	June 2019	5.75	%					42.5		—		—		42.5		—		—		—
Convertible Debenture	December 2019	6.00	%					64.9		—		—		64.9		—		—		—
Total Corporate Debt							$	838.4	$	25.0	$	90.0	$	172.4	$	105.0	$	80.0	$	368.2

⁽¹⁾

The senior secured term loans contain a mandatory amortization feature determined by using the greater of (i) 50% of the cash flow of Atlantic Power Limited Partnership Holdings (“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 senior secured credit facilities and the Medium Term Notes, letters of credit costs to meet the requirements 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 APPEL, 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 senior secured term loans outstanding to achieve a target principal amount that declines quarterly based on a pre-determined specified schedule. Note that failing to meet the mandatory amortization requirements is not an event of default, but could result in APLP Holdings being unable to make distributions to Atlantic Power Corporation and APPEL being unable to pay dividends to its shareholders. The amortization profile in the table above is based on principal payments according to the targeted principal amount described in (ii) above.

⁽²⁾

In October 2017, the interest rate of the senior secured term loans was amended to LIBOR plus an applicable margin of 3.50%.

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. The following table summarizes the maturities of project‑level debt. The amounts represent our share of the non‑recourse project‑level debt balances at September 30, 2017. 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 November 7, 2017, all of our projects 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.

The range of interest rates presented represents the rates in effect at September 30, 2017. 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		2017		2018		2019		2020		2021		Thereafter
Consolidated Projects:
Epsilon Power Partners	January 2019	4.45	%				$	8.8	$	1.5	$	6.5	$	0.8	$	—	$	—	$	—
Piedmont (1)	August 2018	8.20	%					54.6		1.2		53.4		—		—		—		—
Cadillac	August 2025	6.09	%					24.8		0.8		3.0		3.1		3.1		2.7		12.1
Total Consolidated Projects								88.2		3.5		62.9		3.9		3.1		2.7		12.1
Equity Method Projects:
Chambers (2)	December 2019 and 2023	4.50	%	-	5.00	%		42.9		—		—		5.2		7.8		8.8		21.1
Total Equity Method Projects								42.9		—		—		5.2		7.8		8.8		21.1
Total Project-Level Debt							$	131.1	$	3.5	$	62.9	$	9.1	$	10.9	$	11.5	$	33.2

⁽¹⁾

In October 2017, Piedmont’s debt was repaid in full.

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⁽²⁾

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 secured term loans, Medium Term Notes and other corporate and project-level debt, funding the repurchase of shares of our common stock, our convertible debentures, our preferred shares (to the extent we choose to pursue any such repurchases), collateral and investment in our projects through capital expenditures, including major maintenance and business development costs and dividend payments to preferred shareholders of a subsidiary company.

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 $5.4 million in 2017 (of which $4.9 million was reinvested in the nine months ended September 30, 2017) in our portfolio, including equity method investments, in the form of project capital expenditures and incur $34.3 million of maintenance expenses (of which $23.6 million was incurred in the nine months ended September 30, 2017). 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, 2016. We do not expect any other material or unusual requirements for cash outflows for 2017 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 2017 as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades.

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 September 30, 2017, 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, 2016.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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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, and they have concluded that these controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the nine months ended September 30, 2017, that have materially affected, or are 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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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, 2016 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, 2016 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 2: UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEED

Share Repurchase Program

On December 29, 2016, we commenced a NCIB that will expire on December 28, 2017 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIBs. Under the NCIB, we may purchase up to approximately 11.3 million common shares (Cdn$37.4 million based on the Cdn$3.31 closing price of our common shares on the TSX on December 31, 2016), or 10% of our public float. Through September 30, 2017, we repurchased and cancelled 0.1 million shares at a cost of $0.2 million. Through September 30, 2017, we also repurchased and cancelled 0.3 million of our Cdn$25.0 par value 4.85% Cumulative Redeemable Preferred Shares, Series 1 at Cdn$15.5 per share for a total payment of Cdn$3.9 million, resulting in a $3.0 million gain recorded in net (loss) income attributable to preferred shares of a subsidiary company in the three and nine months ended September 30, 2017.

Total Number of Shares

Dollar Value of Maximum Number

Total Number of

Average Price Paid

as Part of a Publicly Announced

of Shares to be Purchased Under

Repurchase Period

Shares Purchased

Per Share

Purchase Plan

the Plan

9/1/2017 - 9/30/2017

93,391

Cdn$

2.95

93,391

Cdn$

37,106,361

Total

93,391

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ITEM 6. EXHIBITS

EXHIBIT INDEX


Exhibit No.		Description
10.40 *		Second amendment dated October 18, 2017 to the 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.
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: November 9, 2017	Atlantic Power Corporation


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

Exhibit 10.40

Execution Version

SECOND AMENDMENT

TO CREDIT AND GUARANTY AGREEMENT

THIS SECOND AMENDMENT TO CREDIT AND GUARANTY AGREEMENT (this “ Amendment ”) is dated as of October 18, 2017 and is entered into by and among APLP HOLDINGS LIMITED PARTNERSHIP , a limited partnership formed under the laws of the Province of Ontario, Canada (the “ Borrower ”), by its general partner, ATLANTIC POWER GP II INC. , a corporation organized under the laws of the Province of British Columbia, Canada (in such capacity, the “ General Partner ”), ATLANTIC POWER CORPORATION , a corporation organized under the laws of the Province of British Columbia, Canada (the “ Sponsor ”), GOLDMAN SACHS LENDING PARTNERS LLC (“ Goldman Sachs ”), as Administrative Agent (“ Administrative Agent ”), acting with the consent of the Requisite Lenders and, for purposes of Section VIII hereof, the GUARANTORS listed on the signature pages hereto, and is made with reference to that certain CREDIT AND GUARANTY AGREEMENT dated as of April 13, 2016, as amended by that certain First Amendment to Credit and Guaranty Agreement, dated as of April 17, 2017 (and as further amended through the date hereof, the “Credit Agreement” ) by and among the Borrower, by its General Partner, the Sponsor and the subsidiaries of the Borrower named therein, as Guarantors, the Lenders and L/C Issuers party thereto from time to time, the Administrative Agent and the Collateral Agent. Capitalized terms used herein without definition shall have the same meanings herein as set forth in the Credit Agreement after giving effect to this Amendment.

RECITALS

WHEREAS, the Credit Parties have requested that the Requisite Lenders agree to amend certain provisions of the Credit Agreement as provided for herein;

WHEREAS, subject to the conditions set forth herein, each Lender that has delivered their counterpart signature of this Amendment to the Administrative Agent in accordance with instructions given to the Lenders for delivery of such signatures hereby agrees to such amendment relating to the Credit Agreement as hereinafter set forth;

WHEREAS , each Term Loan Lender under the Credit Agreement immediately prior to the Second Amendment Effective Date (collectively, the “ Existing Term Loan Lenders ”) that executes and delivers a consent to this Amendment in the form of the “Term Loan Lender Consent” attached hereto as Annex I (a “ Term Loan Lender Consent ”) and selects Option A thereunder (the “ Continuing Term Loan Lenders ”) hereby agrees to the terms and conditions of this Amendment;

WHEREAS , each Existing Term Loan Lender that executes and delivers a Term Loan Lender Consent and selects Option B thereunder (the “ Cash Roll Term Loan Lenders ” and, together with the Continuing Term Loan Lenders, the “ Consenting Term Loan Lenders ”) hereby agrees to the terms and conditions of this Amendment and agrees that it shall execute, or shall be deemed to have executed, a counterpart of the Master Assignment and Assumption Agreement substantially in the form attached hereto as Annex III (a “ Master Assignment ”) and shall in accordance therewith sell all of its existing Term Loans as specified in the applicable Master Assignment and commits to repurchase a like amount of the repriced Term Loans via

assignment post-closing, as further set forth in this Amendment;

WHEREAS , each Existing Term Loan Lender that fails to execute and return a Term Loan Lender Consent by 12:00 p.m. (New York City time), on October 6, 2017 (the “ Consent Deadline ”) (each, a “ Non-Consenting Term Loan Lender ”) shall, in accordance with Section 2.24 of the Credit Agreement, assign and delegate, without recourse (in accordance with Section 10.6 of the Credit Agreement), all of its interests, rights and obligations under the Credit Agreement and the related Credit Documents in respect of its existing Term Loans to an assignee that shall assume such obligations as specified in the applicable Master Assignment and Assumption Agreement substantially in the form attached hereto as Annex III (a “ Master Assignment ”), as further set forth in this Amendment;

WHEREAS , each Revolving Lender holding Revolving Loans immediately prior to the Second Amendment Effective Date (the “ Existing Revolving Loans ”) or unused Revolving Commitments immediately prior to the Second Amendment Effective Date (the “ Existing Revolving Commitments ” and, such Revolving Lenders holding such Existing Revolving Loans or Existing Revolving Commitments, the “ Existing Revolving Lenders ” and, together with the Existing Term Loan Lenders, the “ Existing Lenders ”) that executes and delivers a consent to this Amendment in the form of the “Revolving Lender Consent” attached hereto as Annex II (a “ Revolving Lender Consent ”, and the Revolving Lender Consents together with the Term Loan Lender Consents, the “ Lender Consents ”) (collectively, the “ Consenting Revolving Lenders ” and, together with the Consenting Term Loan Lenders, the “ Consenting Lenders ”) will, by the fact of such execution and delivery, be deemed to have consented to the terms of this Amendment;

WHEREAS , each Existing Revolving Lender that fails to execute and return a Revolving Lender Consent by the Consent Deadline (each, a “ Non-Consenting Revolving Lender ”) shall, in accordance with Section 2.24 of the Credit Agreement, assign and delegate, without recourse (in accordance with Section 10.6 of the Credit Agreement), all of its interests, rights and obligations under the Credit Agreement and the related Credit Documents in respect of its Existing Revolving Loans and Existing Revolving Commitments to an assignee that shall assume such obligations as specified in the applicable Master Assignment, as further set forth in this Amendment; and

WHEREAS , each Credit Party party hereto (collectively, the “ Reaffirming Parties ”, and each, a “ Reaffirming Party ”) expects to realize substantial direct and indirect benefits as a result of this Amendment becoming effective and the consummation of the transactions contemplated hereby and agrees to reaffirm its obligations pursuant to the Credit Agreement, the Collateral Documents, and the other Credit Documents to which it is a party.

NOW, THEREFORE , in consideration of the premises and the agreements, provisions and covenants herein contained, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

SECTION I. AMENDMENTS TO CREDIT AGREEMENT.

1.1 Amendments to Section 1: Definitions .

A. Section 1.1 of the Credit Agreement is hereby amended by adding the following definitions in proper alphabetical sequence:

“ Second Amendment ” means that certain Second Amendment Agreement to Credit and Guaranty Agreement dated as of October 18, 2017 among the Borrower, by its General Partner, the Administrative Agent, the Lenders and the Guarantors listed on the signature pages thereto.

“ Second Amendment Effective Date ” means the date of satisfaction of the conditions referred to in Section III of the Second Amendment.

“ Extension Amendment Effective Date ” means the date of satisfaction of the conditions referred to in Section IV of the Second Amendment.

B. Section 1.1 of the Credit Agreement is hereby amended by amending and restating the definition of “ Applicable Margin ” as follows:

“ Applicable Margin ” means (a) prior to the Second Amendment Effective Date, (1) with respect to Revolving Loans that are Eurodollar Rate Loans and Letter of Credit Fees, 4.25% per annum and with respect to Revolving Loans that are Base Rate Loans or Canadian Prime Rate Loans, 3.25% per annum and (2) with respect to Term Loans that are Eurodollar Rate Loans, 4.25% per annum and with respect to Term Loans that are Base Rate Loans, 3.25% per annum , and (b) from and after the Second Amendment Effective Date, (1) with respect to Revolving Loans that are Eurodollar Rate Loans and Letter of Credit Fees, 3.50% per annum and with respect to Revolving Loans that are Base Rate Loans or Canadian Prime Rate Loans, 2.50% per annum and (2) with respect to Term Loans that are Eurodollar Rate Loans, 3.50% per annum and with respect to Term Loans that are Base Rate Loans, 2.50% per annum .

C. Section 1.1 of the Credit Agreement is hereby amended by amending and restating the definition of “ Revolving Commitment Termination Date ” as follows (such amendment the “ Extension Amendment ”):

“ Revolving Commitment Termination Date ” means, (A) prior to the Extension Amendment Effective Date, the earlier of (i) the fifth anniversary of the Effective Date, as extended pursuant to Section 2.25, if applicable; (ii) the date the Revolving Commitments are permanently reduced to zero pursuant to Section 2.14(b) or 2.15; and (iii) the date of the termination of the Revolving Commitments pursuant to Section 8.1, and (B) upon and after the Extension Amendment Effective Date, the earlier of (i) the sixth anniversary of the Effective Date, as extended pursuant to Section 2.25, if applicable; (ii) the date the Revolving Commitments are permanently reduced to zero pursuant to Section 2.14(b) or 2.15; and (iii) the date of the termination of the Revolving Commitments pursuant to Section 8.1.

1.2 Amendments to Section 2.14 .

Section 2.14(c) of the Credit Agreement is hereby amended by replacing the phrase “the date that is six (6) months after the First Amendment Effective Date ( provided that the reduction in the interest rate as implemented by the First Amendment shall not be considered a Repricing Transaction)” therein with the phrase “the date that is six (6) months after the Second Amendment Effective Date ( provided that the reduction in the interest rate as implemented by the Second Amendment shall not be considered a Repricing Transaction)” in each of such places it appears in such Section (such amendment, along with the Amendments in Sections 1.1(A) and Sections 1.1(B) above, the “Repricing Amendments ”).

SECTION II. CONTINUATION OF EXISTING LOANS; NON-CONSENTING LENDERS; OTHER TERMS AND AGREEMENTS.

2.1 Continuing Lenders. Each Existing Term Loan Lender selecting Option A on the Term Loan Lender Consent hereby consents and agrees to this Amendment. Each Existing Revolving Lender executing and delivering a Revolving Lender Consent hereby consents and agrees to this Amendment.

2.2 Cash Roll Term Loan Lenders. Each Existing Term Loan Lender hereto selecting Option B on the Term Loan Lender Consent hereby consents and agrees (subject to the effectiveness of the assignment referred to in the following clause (ii)) to (i) this Amendment, (ii) sell the entire principal amount of its existing Term Loans via an assignment on the Second Amendment Effective Date pursuant to a Master Assignment and (iii) commit to repurchase a like amount of the repriced Term Loans via an assignment after the Second Amendment Effective Date. By executing a Term Loan Lender Consent and selecting Option B, each Cash Roll Term Loan Lender shall be deemed to have executed a counterpart to the applicable Master Assignment to give effect, solely upon the consent and acceptance by the Replacement Lender, to the assignment described in clause (ii) of the immediately preceding sentence.

2.3 Non-Consenting Term Loan Lenders. The Borrower hereby gives notice to each Non-Consenting Term Loan Lender that, upon receipt of Lender Consents from the Existing Lenders constituting the Requisite Lenders and Lenders holding more than 50% of the aggregate outstanding principal amount of the Term Loans immediately prior to the Second Amendment Effective Date, if such Non-Consenting Term Loan Lender has not executed and delivered a Term Loan Lender Consent on or prior to the Consent Deadline, such Non- Consenting Term Loan Lender shall, pursuant to Section 2.24 of the Credit Agreement, execute within one (1) Business Day after the Second Amendment Effective Date or be deemed to have executed a counterpart of the applicable Master Assignment and shall in accordance therewith sell its Existing Terms Loans as specified in the Master Assignment. Pursuant to the Master Assignment, each Non-Consenting Term Loan Lender shall sell and assign the principal amount of its Existing Term Loans as set forth in Schedule I to the Master Assignment, as such Schedule is completed by the Administrative Agent on or prior to the Second Amendment Effective Date, to Goldman Sachs, as assignee (in such capacity the “ Replacement Lender ”) under such Master Assignment, solely upon the consent and acceptance by the Replacement Lender. The Replacement Lender shall be deemed to have consented to this Amendment with respect to such purchased Term Loans at the time of such assignment.

2.4 Non-Consenting Revolving Lenders. The Borrower hereby gives notice to each Non-Consenting Revolving Lender that, upon receipt of Lender Consents from the Existing Lenders constituting the Requisite Lenders and Lenders holding more than 50% of the aggregate amount of the Revolving Commitments immediately prior to the Second Amendment Effective Date, if such Non-Consenting Revolving Lender has not executed and delivered a Revolving Lender Consent on or prior to the Consent Deadline, such Non-Consenting Revolving Lender shall, pursuant to Section 2.24 of the Credit Agreement, execute within one (1) Business Day after the Second Amendment Effective Date or be deemed to have executed a counterpart of the applicable Master Assignment and shall in accordance therewith sell its Existing Revolving Loans and Existing Revolving Commitments as specified in the Master Assignment. Pursuant to the Master Assignment, each Non-Consenting Revolving Lender shall sell and assign the principal amount of its Existing Revolving Loans and Existing Revolving Commitments as set forth in Schedule I to the Master Assignment, as such Schedule is completed by the Administrative Agent on or prior to the Second Amendment Effective Date, to the Replacement Lender under such Master Assignment, solely upon the consent and acceptance by the Replacement Lender. The Replacement Lender shall be deemed to have consented to this Amendment with respect to such purchased Revolving Loans and Revolving Commitments at the time of such assignment.

SECTION III. CONDITIONS TO EFFECTIVENESS.

The Repricing Amendments shall become effective as of the date hereof only upon the satisfaction of all of the following conditions precedent (the date of satisfaction of such conditions being referred to herein as the “ Second Amendment Effective Date ”):

A. Execution . Administrative Agent shall have received a counterpart signature page of this Amendment duly executed by (i) each of the Credit Parties and the General Partner and (ii) the Lenders under the Credit Agreement consisting of at least the Requisite Lenders.

B. Fees; Interest .

(a) The Administrative Agent shall have received (i) all fees, costs, expenses and other amounts due and payable on or prior to the Second Amendment Effective Date, including, to the extent invoiced, reimbursement or other payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder or any other Credit Document and (ii) for the account of each Lender, all interest accrued but unpaid on all existing Loans through the Second Amendment Effective Date.

(b) The Arrangers, as Repricing Arrangers (as defined below), shall have each received all fees due and payable under that certain engagement letter, dated as of October 2, 2017, by and among the Sponsor and the Arrangers (the “ Second Amendment Engagement Letter ”), and the fee letters between the Sponsor and each Arranger, dated as of October 2, 2017, respectively.

C. Legal Opinions. The Administrative Agent shall have received a favorable opinion of (a) Norton Rose Fulbright US LLP, New York, Delaware and California special counsel to the Credit Parties and (b) Goodmans LLP, Burnet, Duckworth & Palmer LLP and MLT Atkins LLP,

local Canadian counsel to the Credit Parties, in each case in form and substance satisfactory to the Administrative Agent.

D. Second Amendment Effective Date Certificate. The Administrative Agent shall have received a certificate signed by a Responsible Officer of the Borrower as to the matters set forth in paragraphs (F) and (G) of this Section III .

E. Organizational Documents; Incumbency. The Administrative Agent shall have received, in respect of each Credit Party and the General Partner, a certificate dated as of the Second Amendment Effective Date of the secretary or an assistant secretary or director (or such other officer reasonably acceptable to the Administrative Agent) of such party, in form and substance reasonably satisfactory to the Administrative Agent, certifying (i) that either (A) attached thereto is a true and complete and up to date copy of the Organizational Documents including any certificate on change of name and all amendments thereto of such Credit Party or the General Partner, as applicable, certified as of a recent date by the Secretary of State (or comparable Governmental Authority) of its jurisdiction of organization (where applicable), and that the same has not been amended since the date of such certification or (B) the Organizational Documents of such Credit Party or the General Partner, as applicable, delivered on the Effective Date to the Administrative Agent have not been amended and are in full force and effect; (ii) that either (A) attached thereto is a true and complete copy of the bylaws or comparable governing documents of such Credit Party or the General Partner, as applicable, as then in effect and as in effect at all times without amendment of supersession from the date on which the resolutions referred to in clause (iii) below were adopted to and including the date of such certificate or (B) that the bylaws or comparable governing documents of such Credit Party or the General Partner, as applicable, delivered on the Effective Date to the Administrative Agent have not been amended and are in full force and effect; (iii) that attached thereto is a true and complete copy of resolutions of the board of directors or similar governing body of such Credit Party (or, in the case of a limited partnership, of the general partner, acting on behalf of such limited partnership) and the General Partner, acting in its own capacity, approving and, to the extent required in any jurisdiction, resolutions of the meeting of shareholders of a Credit Party (or, in the case of a limited partnership, of the general partner, acting on behalf of such limited partnership) and the General Partner, acting in its own capacity, in each case, authorizing the execution, delivery and performance of this Amendment and any related Credit Documents to which it is a party which are in full force and effect without amendment or supersession as of the date of the certificate; (iv) a good standing certificate (to the extent such concept is known in the relevant jurisdiction) from the applicable Governmental Authority of such Credit Party’s or the General Partner’s, as applicable, jurisdiction of incorporation, organization or formation dated the Second Amendment Effective Date or a recent date prior thereto; and (v) as to the incumbency and genuineness of the signature of each officer, director or other comparable authorized manager or attorney of such Credit Party or the General Partner, as applicable, executing this Amendment or any of such other Credit Documents, and attaching all such copies of the documents described above.

F. No Default. No Default or Event of Default has occurred and is continuing both before and immediately after giving effect to the transactions contemplated hereby.

G. Representations and Warranties. The representations and warranties of the Borrower and each of the Guarantors set forth in Section V of this Amendment are true and correct.

H. Master Assignment. The Replacement Lender shall have executed and delivered the Master Assignment contemplated by Section II above and all conditions to the consummation of the assignments in accordance with Section II above shall have been satisfied and such assignments shall have been consummated.

I. Non-Consenting Lenders. The Borrower shall have, substantially concurrently with the effectiveness of this Amendment, paid to all Non-Consenting Term Loan Lenders and Non-Consenting Revolving Lenders all indemnities, fees, cost reimbursements and other Obligations (other than interest payable under Section III.B. above and principal and all other amounts paid to such Non-Consenting Term Loan Lender or Non-Consenting Revolving Lender under Section II above), if any, then due and owing to such Non-Consenting Term Loan Lenders and Non-Consenting Revolving Lenders under the Credit Agreement and the other Credit Documents (immediately prior to the Second Amendment Effective Date).

J. Necessary Consents. Each Credit Party shall have obtained all material consents necessary or advisable in connection with the transactions contemplated by this Amendment.

SECTION IV. CONDITIONS TO EXTENSION AMENDMENT EFFECTIVENESS

The Extension Amendment shall become effective only upon the satisfaction of all of the following conditions precedent (the date of satisfaction of such conditions being referred to herein as the “ Extension Amendment Effective Date ”):

A. Fees. Each Consenting Revolving Lender shall have received a fee in an amount equal to 0.125% of such Consenting Revolving Lender’s Revolving Exposure that such Consenting Revolving Lender has agreed to extend.

B. Revolving Lender Consent . Each of those certain Revolving Lenders specifically identified to the Administrative Agent and the Borrower prior to the date hereof shall have confirmed in writing satisfactory to the Administrative Agent that it consents to the Extension Amendment.

C. No Default. No Default or Event of Default has occurred and is continuing both before and immediately after giving effect to the transactions contemplated by the Extension Amendment.

D. Representations and Warranties. The representations and warranties of the Borrower and each of the Guarantors set forth in Section V of this Amendment are true and correct.

E. Extension Amendment Effective Date Certificate. The Administrative Agent shall have received a certificate signed by a Responsible Officer of the Borrower as to the matters set forth in paragraphs (C) and (D) of this Section IV .

SECTION V. REPRESENTATIONS AND WARRANTIES.

In order to induce the other parties hereto to enter into this Amendment and to amend the Credit Agreement in the manner provided herein, each Credit Party represents and warrants to each of the Lenders and the Administrative Agent that, as of the Second Amendment Effective Date and Extension Amendment Effective Date, as applicable):

A. Corporate Power and Authority. Each Credit Party, which is party hereto, has all requisite power and authority to enter into this Amendment and to carry out the transactions contemplated by, and perform its obligations under, the Credit Agreement as amended by this Amendment (the “ Amended Agreement ”) and the other Credit Documents.

B. Authorization of Agreements. The execution and delivery of this Amendment and the performance of the Amended Agreement and the other Credit Documents have been duly authorized by all necessary action on the part of each Credit Party.

C. No Conflict. The execution and delivery by each Credit Party of this Amendment and the performance by each Credit Party of the Amended Agreement and the other Credit Documents do not and will not (i) violate (A) any provision of any law, statute, rule or regulation, or of the certificate or articles of incorporation or partnership agreement, other constitutive documents or by-laws of Holdings, the Borrower or any Credit Party or (B) any applicable order of any court or any rule, regulation or order of any Governmental Authority, (ii) be in conflict with, result in a breach of or constitute (alone or with notice or lapse of time or both) a default under any Contractual Obligation of the applicable Credit Party, where any such conflict, violation, breach or default referred to in clause (i) or (ii) of this Section V.C. , individually or in the aggregate could reasonably be expected to have a Material Adverse Effect, (iii) except as permitted under the Amended Agreement, result in or require the creation or imposition of any Lien upon any of the properties or assets of each Credit Party (other than any Liens created under any of the Credit Documents in favor of Administrative Agent on behalf of Lenders), or (iv) require any approval of stockholders or partners or any approval or consent of any Person under any Contractual Obligation of each Credit Party, except for such approvals or consents which will be obtained on or before the Second Amendment Effective Date and except for any such approvals or consents the failure of which to obtain will not have a Material Adverse Effect.

D. Governmental Consents. No action, consent or approval of, registration or filing with or any other action by any Governmental Authority is or will be required in connection with the execution and delivery by each Credit Party of this Amendment and the performance by the Borrower and Holdings of the Amended Agreement and the other Credit Documents, except for such actions, consents and approvals the failure to obtain or make which could not reasonably be expected to result in a Material Adverse Effect or which have been obtained and are in full force and effect.

E. Binding Obligation. This Amendment and the Amended Agreement have been duly executed and delivered by each of the Credit Parties party thereto and each constitutes a legal, valid and binding obligation of such Credit Party to the extent a party thereto, enforceable against such Credit Party in accordance with its terms, except as enforceability may be limited by

bankruptcy, insolvency, moratorium, reorganization or other similar laws affecting creditors’ rights generally and except as enforceability may be limited by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

F. Incorporation of Representations and Warranties from Credit Agreement. The representations and warranties (a) contained in Section 4 of the Amended Agreement (other than Section 4.24) are and will be true and correct in all material respects on and as of the Second Amendment Effective Date and the Extension Amendment Effective Date to the same extent as though made on and as of that date, except to the extent such representations and warranties specifically relate to an earlier date, in which case they were true and correct in all material respects on and as of such earlier date and (b) contained in Section 4.24 of the Amended Agreement are and will be true and correct in all material respects on and as of the Second Amendment Effective Date and the Extension Amendment Effective Date to the same extent as though made on and as of that date, except to the extent such representations and warranties (x) specifically relate to an earlier date, in which case they were true and correct in all material respects on and as of such earlier date, or (y) have been updated, modified, supplemented or otherwise superseded by information contained in the most recent Form 10-K and Form 10-Q and any Form 8-K (to the extent such Form 8-K was filed on or after the date of the most recent Form 10-Q) filed by the Sponsor with the Securities and Exchange Commission, in which case they were true and correct in all material respects on and as of the date of the most recent Form 10-K and Form 10-Q and any such Form 8-K and will be true and correct in all material respects on and as of the Second Amendment Effective Date and the Extension Amendment Effective Date to the same extent as though made on and as of that date; provided that, in each case, such materiality qualifier shall not be applicable to any representations and warranties that already are qualified or modified by materiality in the text thereof.

G. Absence of Default. No event has occurred and is continuing or will result from the consummation of the transactions contemplated by this Amendment that would constitute an Event of Default or a Default.

SECTION VI. BORROWER’S CONSENT.

For purposes of Section 10.6 of the Credit Agreement, the Borrower hereby consents to any assignee of the Replacement Lender or any of its respective Affiliates (in each case otherwise being an Eligible Assignee) becoming a Term Loan Lender and/or Revolving Lender, as applicable, in connection with the syndication of the Term Loans and Revolving Commitments acquired by the Replacement Lender pursuant to Section II hereof.

SECTION VII. REPRICING ARRANGERS.

The Credit Parties and the Lenders party hereto agree that (a) the Arrangers, in their respective capacity as joint lead arranger with respect to this Amendment (collectively, the “ Repricing Arrangers ”), shall be entitled to the privileges, indemnification, immunities and other benefits afforded to the Arrangers under the Amended Agreement and (b) except as otherwise agreed to in writing by the Borrower, the General Partner and the Repricing Arrangers, the Repricing Arrangers shall have no duties, responsibilities or liabilities with respect to this

Amendment, the Amended Agreement or any other Credit Document.

SECTION VIII. INDEMNIFICATION.

Each Credit Party hereby confirms that the indemnification provisions set forth in Section 10.3 of the Amended Agreement shall apply to this Amendment and the transactions contemplated hereby.

SECTION IX. REAFFIRMATION.

Each of the Reaffirming Parties, as party to the Credit Agreement and certain of the Collateral Documents and the other Credit Documents, in each case as amended, supplemented or otherwise modified from time to time, hereby (i) acknowledges and agrees that all of its obligations under the Credit Agreement, the Collateral Documents and the other Credit Documents to which it is a party are reaffirmed and remain in full force and effect on a continuous basis, (ii) reaffirms (A) each Lien granted by it to the Administrative Agent for the benefit of the Secured Parties and (B) any guaranties made by it pursuant to the Credit Agreement, (iii) acknowledges and agrees that the grants of security interests by it contained in any Collateral Document to which it is a party shall remain, in full force and effect after giving effect to this Amendment, and (iv) agrees that the Obligations include, among other things and without limitation, the prompt and complete payment and performance by the Borrower when due and payable (whether at the stated maturity, by acceleration or otherwise) of principal and interest on, and premium (if any) on, the Term Loans under the Amended Agreement. Nothing contained in this Amendment shall be construed as substitution or novation of the obligations outstanding under the Credit Agreement or the other Credit Documents, which shall remain in full force and effect, except to any extent modified hereby

Each Guarantor acknowledges and agrees that (i) notwithstanding the conditions to effectiveness set forth in this Amendment, such Guarantor is not required by the terms of the Credit Agreement or any other Credit Document to consent to the amendments to the Credit Agreement effected pursuant to this Amendment and (ii) nothing in the Credit Agreement, this Amendment or any other Credit Document shall be deemed to require the consent of such Guarantor to any future amendments to the Credit Agreement.

SECTION X. ADMINISTRATIVE AGENT.

The Credit Parties acknowledge and agree that Goldman Sachs, in its capacity as administrative agent under the Credit Agreement, will serve as Administrative Agent under this Amendment and under the Amended Agreement.

SECTION XI. MISCELLANEOUS.

A. Reference to and Effect on the Credit Agreement and the Other Credit Documents .

(i) On and after the Second Amendment Effective Date, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein” or words of like import referring to the Credit Agreement, and each reference in the

other Credit Documents to the “Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement shall mean and be a reference to the Credit Agreement as amended by this Amendment.

(ii) Except as specifically amended by this Amendment, the Credit Agreement and the other Credit Documents shall remain in full force and effect and are hereby ratified and confirmed.

(iii) The execution, delivery and performance of this Amendment shall not constitute a waiver of any provision of, or operate as a waiver of any right, power or remedy of any Agent or Lender under, the Credit Agreement or any of the other Credit Documents.

(iv) This Amendment shall be deemed to be a Credit Document as defined in the Credit Agreement.

B. Headings . Section and Subsection headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose or be given any substantive effect.

C. Applicable Law . THIS AMENDMENT AND THE RIGHTS AND OB- LIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF ANY LAW OTHER THAN THE LAW OF THE STATE OF NEW YORK.

D. Jurisdiction; Waiver of Jury Trial . The provisions of Sections 10.15 and 10.16 of the Credit Agreement pertaining to consent to jurisdiction, service of process, and waiver of jury trial are hereby incorporated by reference herein, mutatis mutandis .

E. Counterparts . This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument; signature pages may be detached from multiple separate counterparts and attached to a single counterpart so that all signature pages are physically attached to the same document. Delivery of an executed counterpart of a signature page of this Amendment by facsimile or in electronic format (e.g., “pdf” or “tif” file format) shall be effective as delivery of a manually executed counterpart of this Amendment.

F. Severability . Any term or provision of this Amendment which is invalid or unenforceable in any jurisdiction shall, as to that jurisdiction, be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Amendment or affecting the validity or enforceability of any of the terms or provisions of this Amendment in any other jurisdiction. If any provision of this Amendment is so broad as to be unenforceable, the provision shall be interpreted to be only so broad as would be enforceable.

ANNEX III TO SECOND AMENDMENT

FORM OF MASTER ASSIGNMENT AND ASSUMPTION AGREEMENT

This Assignment and Assumption Agreement (this “ Master Assignment ”) is dated as of the Effective Date set forth below and is entered into by and between each Assignor identified in Section 1 below (each, an “ Assignor ”) and Goldman Sachs Lending Partners LLC (the “ Assignee ”). Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as it may be amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “ Credit Agreement ”), receipt of a copy of which is hereby acknowledged by the Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment as if set forth herein in full.

For an agreed consideration, each Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the applicable Assignor, subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below, (i) all of the applicable Assignor’s rights and obligations in its capacity as a Term Loan Lender and/or Revolving Lender under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest of all of the applicable Assignor’s outstanding rights and obligations under the respective facilities identified opposite such Assignor’s name on Schedule I hereto (including, without limitation, any letters of credit, guaranties, and swingline loans included in such facilities), and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the applicable Assignor (in its capacity as a Term Loan Lender and/or Revolving Lender) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by the applicable Assignor to the Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as the “ Assigned Interest ”). Such sale and assignment is without recourse to any Assignor and, except as expressly provided in this Assignment, without representation or warranty by any Assignor.

By purchasing the Assigned Interest, the Assignee agrees that, for purposes of that certain Second Amendment to Credit and Guaranty Agreement, dated as of October 18, 2017 (the “ Second Amendment ”), by and among the Borrower, by its General Partner, the Sponsor and certain subsidiaries of the Borrower, as Guarantors, the Requisite Lenders, the Replacement Lender and the Consenting Lenders referred to therein and the Administrative Agent, it shall be deemed to have consented and agreed to the Second Amendment.

ANNEX III- 1


1.	Assignor:	Each person identified on Schedule I hereto
	Assignee:	GOLDMAN SACHS LENDING PARTNERS LLC
3.	Borrower:	APLP HOLDINGS LIMITED PARTNERSHIP
4.	Administrative Agent:	GOLDMAN SACHS LENDING PARTNERS LLC, as the administrative agent under the Credit Agreement
5.	Credit Agreement:	The Credit and Guaranty Agreement, dated as of April 13, 2016, as amended by that certain First Amendment to Credit and Guaranty Agreement, dated as of April 17, 2017 (as it may be further amended, restated, extended, supplemented or otherwise modified from time to time; the terms defined therein and not otherwise defined herein being used herein as therein defined), by and among the Borrower, by its General Partner, ATLANTIC POWER GP II INC ., ATLANTIC POWER CORPORATION (“ Sponsor ”) and certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto from time to time, GOLDMAN SACHS BANK USA and BANK OF AMERICA, N.A. (“ Bank of America ”) , as L/C Issuers, GOLDMAN SACHS LENDING PARTNERS LLC (“ Goldman Sachs ”) and Bank of America, as Joint Syndication Agents, Goldman Sachs as Administrative Agent (together with its permitted successors in such capacity, “ Administrative Agent ”) and as Collateral Agent (together with its permitted successors in such capacity, “ Collateral Agent ”), Goldman Sachs, MERRILL LYNCH, PIERCE, FENNER & SMITH INCORPORATED , RBC CAPITAL MARKETS , THE BANK OF TOKYO-MITSUBISHI UFJ, LTD. , a member of MUFG, a global financial group, WELLS FARGO SECURITIES, LLC , and INDUSTRIAL AND COMMERCIAL BANK OF CHINA LIMITED, NEW YORK BRANCH , in their respective capacities as Arrangers and Bookrunners.
6.	Assigned Interests:	As indicated on Schedule I hereto.

Effective Date: October 18, 2017

ANNEX III- 2

ANNEX 1

STANDARD TERMS AND CONDITIONS FOR MASTER ASSIGNMENT AND ASSUMPTION AGREEMENT

1. Representations and Warranties .

1.1 Assignor . Each Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and to consummate the transactions contemplated hereby and (iv) it is not a Defaulting Lender; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with any Credit Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Credit Agreement or any other instrument or document delivered pursuant thereto, other than this Assignment (herein collectively the “ Credit Documents ”), or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Credit Document or (iv) the performance or observance by the Borrower, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Credit Document.

1.2 Assignee . The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all requirements of an Eligible Assignee under the Credit Agreement, (iii) from and after the Effective Date of the assignment, it shall be bound by the provisions of the Credit Agreement and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 5.1 thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and to purchase the Assigned Interest, (vi) it has, independently and without reliance upon Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and to purchase the Assigned Interest, and (vii) attached to this Assignment is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement (in particular, as prescribed in Section 2.21(c) thereof), duly completed and executed by the Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, the Assignor or any other Lender, and based on such

ANNEX III- 3

documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Credit Documents are required to be performed by it as a Lender.

2. Payments . All payments with respect to the Assigned Interests shall be made on the Effective Date as follows:

2.1 From and after the Effective Date of the assignment, the Administrative Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and other amounts) to the applicable Assignor for amounts which have accrued to but excluding the Effective Date of the assignment and to the Assignee for amounts which have accrued from and after the Effective Date of the assignment. Notwithstanding the foregoing, the Administrative Agent shall make all payments of interest, fees or other amounts paid or payable in kind from and after the Effective Date of the assignment to the Assignee.

3. General Provisions . This Assignment shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment by telecopy shall be effective as delivery of a manually executed counterpart of this Assignment. THIS ASSIGNMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICT OF LAWS PRINCIPLES THEREOF THAT WOULD RESULT IN THE APPLICATION OF ANY LAW OTHER THAN THE STATE OF NEW YORK.

[ Remainder of page intentionally left blank . ]

ANNEX III- 4

SCHEDULE I TO

MASTER ASSIGNMENT AND ASSUMPTION

Term Loans

Assignor	Aggregate Amount of Commitments/Loans for all Lenders	Amount of Commitment/Loans Assigned	Percentage Assigned of Commitment/Loans 1
[  ]	$[  ]	$[  ]	[  ]%
[  ]	$[  ]	$[  ]	[  ]%

Revolving Commitments/Revolving Loans

Assignor	Aggregate Amount of Commitments/Loans for all Lenders	Amount of Commitment/Loans Assigned	Percentage Assigned of Commitment/Loans 2
[  ]	$[  ]	$[  ]	[  ]%
[  ]	$[  ]	$[  ]	[  ]%

1 Set forth, to at least 9 decimals, as a percentage of the Commitment/Loans of all Lenders thereunder.

2 Set forth, to at least 9 decimals, as a percentage of the Commitment/Loans of all Lenders thereunder.

ANNEX III- 5

Exhibit 31.1

Certifications

I, James J. Moore, certify that:

I have reviewed this Quarterly Report on Form 10‑Q of Atlantic Power Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: November 9, 2017	/s/ James J. Moore, Jr.
	James J. Moore, Jr.
	President and Chief Executive Officer

Exhibit 31.2

Certifications

I, Terrence Ronan, certify that:

I have reviewed this Quarterly Report on Form 10‑Q of Atlantic Power Corporation;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

ay
Date: November 9, 2017	/s/ Terrence Ronan
	Terrence Ronan
	Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES‑OXLEY ACT OF 2002

The undersigned officer of Atlantic Power Corporation (the “Company”) hereby certifies to his knowledge that the Company’s Quarterly Report on Form 10‑Q for the period ended September 30, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date: November 9, 2017	/s/ James J. Moore, Jr.
	James J. Moore, Jr.
	President and Chief Executive Officer

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES‑OXLEY ACT OF 2002


Date: November 9, 2017	/s/ Terrence Ronan
	Terrence Ronan
	Chief Financial Officer