Edgar Filing: ATLANTIC POWER CORP

at_Current_Folio_10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10‑Q


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2018
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 August 1, 2018 was 111,302,692.

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ATLANTIC POWER CORPORATION

FORM 10‑Q

THREE AND SIX MONTHS ENDED JUNE 30, 2018

Index

	General :		3
		PART I—FINANCIAL INFORMATION
ITEM 1.		CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
		Consolidated Balance Sheets as of June 30, 2018 (unaudited) and December 31, 2017	4
		Consolidated Statements of Operations for the three and six months ended June 30, 2018 (unaudited) and June 30, 2017 (unaudited)	5
		Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2018 (unaudited) and June 30, 2017 (unaudited)	6
		Consolidated Statements of Cash Flows for the six months ended June 30, 2018 (unaudited) and June 30, 2017 (unaudited)	7
		Condensed Notes to Consolidated Financial Statements (unaudited)	8
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	36
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
ITEM 4.		CONTROLS AND PROCEDURES	60
		PART II—OTHER INFORMATION
ITEM 1A.		RISK FACTORS	60
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
ITEM 6.		EXHIBITS	62

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GENERAL

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

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

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ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions of U.S. dollars)


	June 30,		December 31,
	2018		2017
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	80.8	$	78.7
Restricted cash		1.9		6.2
Accounts receivable		25.3		52.7
Current portion of derivative instruments asset (Notes 7 and 8)		5.9		2.7
Inventory		14.0		17.7
Prepayments		4.3		6.9
Income taxes receivable		0.5		1.0
Other current assets		3.6		3.1
Total current assets		136.3		169.0
Property, plant, and equipment, net		573.1		602.3
Equity investments in unconsolidated affiliates (Note 4)		160.9		163.7
Power purchase agreements and intangible assets, net		166.3		191.2
Goodwill		21.4		21.3
Derivative instruments asset (Notes 7 and 8)		2.6		2.8
Other assets		7.2		8.5
Total assets	$	1,067.8	$	1,158.8
Liabilities
Current liabilities:
Accounts payable	$	1.4	$	2.2
Accrued interest		0.2		0.3
Other accrued liabilities		16.9		25.5
Current portion of long-term debt (Note 5)		78.0		99.5
Current portion of derivative instruments liability (Notes 7 and 8)		6.1		4.4
Other current liabilities		0.7		1.0
Total current liabilities		103.3		132.9
Long-term debt, net of unamortized discount and deferred financing costs (Note 5)		574.6		616.3
Convertible debentures, net of discount and unamortized deferred financing costs (Note 6)		97.0		105.4
Derivative instruments liability (Notes 7 and 8)		17.7		19.9
Deferred income taxes		14.3		11.7
Power purchase and fuel supply agreement liabilities, net		22.5		24.1
Asset retirement obligations, net		44.7		45.3
Other long-term liabilities		5.8		6.4
Total liabilities		879.9		962.0
Equity
Common shares, no par value, unlimited authorized shares; 111,666,941 and 115,211,976 issued and outstanding at June 30, 2018 and December 31, 2017		1,266.8		1,274.8
Accumulated other comprehensive loss (Note 3)		(141.9)		(134.8)
Retained deficit		(1,143.3)		(1,158.4)
Total Atlantic Power Corporation shareholders’ equity		(18.4)		(18.4)
Preferred shares issued by a subsidiary company (Note 12)		206.3		215.2
Total equity		187.9		196.8
Total liabilities and equity	$	1,067.8	$	1,158.8

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 June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Project revenue:
Energy sales (Note 2)	$	31.4	$	40.0	$	69.8	$	77.1
Energy capacity revenue (Note 2)		23.3		28.3		43.4		47.8
Other (Note 2)		11.5		55.7		33.0		97.5
		66.2		124.0		146.2		222.4
Project expenses:
Fuel		15.0		24.0		37.2		52.9
Operations and maintenance		27.2		23.3		48.5		43.6
Depreciation and amortization		21.0		29.5		44.7		59.0
		63.2		76.8		130.4		155.5
Project other income (loss):
Change in fair value of derivative instruments (Notes 7 and 8)		(0.2)		(2.7)		3.5		(3.9)
Equity in earnings (loss) of unconsolidated affiliates (Note 4)		11.2		(54.4)		23.5		(45.4)
Interest, net		(0.4)		(2.2)		(1.0)		(4.4)
		10.6		(59.3)		26.0		(53.7)
Project income (loss)		13.6		(12.1)		41.8		13.2
Administrative and other expenses:
Administration		6.2		5.7		12.2		12.1
Interest expense, net		11.1		18.4		26.1		35.7
Foreign exchange (gain) loss		(5.4)		5.9		(13.6)		8.3
Other income, net (Note 8)		(0.2)		—		(2.2)		—
		11.7		30.0		22.5		56.1
Income (loss) from operations before income taxes		1.9		(42.1)		19.3		(42.9)
Income tax expense (benefit) (Note 9)		0.9		(22.3)		4.2		(22.6)
Net income (loss)		1.0		(19.8)		15.1		(20.3)
Net income (loss) attributable to preferred shares of a subsidiary company (Note 12)		1.6		2.1		(0.1)		4.3
Net (loss) income attributable to Atlantic Power Corporation	$	(0.6)	$	(21.9)	$	15.2	$	(24.6)
Net (loss) income per share attributable to Atlantic Power Corporation shareholders: (Note 11)
Basic	$	(0.01)	$	(0.19)	$	0.13	$	(0.21)
Diluted		(0.01)		(0.19)		0.13		(0.21)
Weighted average number of common shares outstanding: (Note 11)
Basic		112.4		115.2		113.6		115.0
Diluted		112.4		115.2		140.1		115.0

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions of U.S. dollars)

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Net income (loss)	$	1.0	$	(19.8)	$	15.1	$	(20.3)
Other comprehensive (loss) income, net of tax:
Unrealized gain (loss) on hedging activities	$	—	$	(0.1)	$	0.2	$	(0.3)
Net amount reclassified to earnings		0.1		0.1		0.2		0.4
Net unrealized gain on derivatives		0.1		—		0.4		0.1
Defined benefit plan, net of tax		—		—		—		0.1
Foreign currency translation adjustments		(2.9)		4.7		(7.5)		6.7
Other comprehensive (loss) income, net of tax		(2.8)		4.7		(7.1)		6.9
Comprehensive (loss) income		(1.8)		(15.1)		8.0		(13.4)
Less: Comprehensive income (loss) attributable to preferred shares of a subsidiary company		1.6		2.1		(0.1)		4.3
Comprehensive (loss) income attributable to Atlantic Power Corporation	$	(3.4)	$	(17.2)	$	8.1	$	(17.7)

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions of U.S. dollars)

(Unaudited)


	Six months ended
	June 30,
	2018		2017
Cash provided by operating activities:
Net income (loss)	$	15.1	$	(20.3)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		44.7		59.0
Share-based compensation		1.1		1.1
Equity in (earnings) loss from unconsolidated affiliates		(23.5)		45.4
Distributions from unconsolidated affiliates		27.3		17.2
Unrealized foreign exchange (gain) loss		(13.3)		8.3
Change in fair value of derivative instruments		(3.6)		3.9
Change in fair value of convertible debenture conversion option derivative		(2.3)		—
Amortization of debt discount and deferred financing costs		5.4		5.2
Change in deferred income taxes		2.0		(24.9)
Change in other operating balances
Accounts receivable		27.4		(5.0)
Inventory		3.7		(3.4)
Prepayments and other assets		3.8		(0.3)
Accounts payable		(1.9)		(1.4)
Accruals and other liabilities		(7.5)		0.9
Cash provided by operating activities		78.4		85.7
Cash used in investing activities:
Investment in unconsolidated affiliate		(1.1)		—
Purchase of property, plant and equipment		(1.3)		(4.2)
Cash used in investing activities		(2.4)		(4.2)
Cash used in financing activities:
Proceeds from convertible debenture issuance		92.2		—
Repayment of convertible debentures		(88.0)		—
Common share repurchases		(9.2)		—
Preferred share repurchases		(4.5)		—
Repayment of corporate and project-level debt		(58.8)		(56.9)
Cash payments for vested LTIP units withheld for taxes		(0.8)		(0.7)
Deferred financing costs		(4.8)		—
Dividends paid to preferred shareholders		(4.3)		(4.3)
Cash used in financing activities:		(78.2)		(61.9)
Net (decrease) increase in cash, restricted cash and cash equivalents		(2.2)		19.6
Cash, restricted cash and cash equivalents at beginning of period		84.9		98.8
Cash, restricted cash and cash equivalents at end of period	$	82.7	$	118.4
Supplemental cash flow information
Interest paid	$	20.2	$	33.4
Income taxes paid, net	$	1.9	$	2.2
Accruals for construction in progress	$	0.1	$	1.3

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 is an independent power producer that owns power generation assets in nine states in the United States and two provinces in Canada. Our power generation projects, which are diversified by geography, fuel type, dispatch profile and offtaker, sell electricity to utilities and other large customers predominantly under long‑term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of June 30, 2018, the Company’s portfolio consisted of twenty-two projects with an aggregate electric generating capacity of approximately 1,793 megawatts (“MW”) on a gross ownership basis and approximately 1,440 MW on a net ownership basis. Eighteen of the projects are majority‑owned and operated by the Company. At June 30, 2018, three of our Ontario projects were not in operation, two because of contract expirations on December 31, 2017, and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence with commercial operation of the plant in the fourth quarter of 2018. In early February 2018, our three plants in San Diego, totaling 112 MW on a gross and net ownership basis, ceased operations. The sixteen projects in operation at June 30, 2018 have generating capacity of approximately 1,561 MW on a gross ownership basis and approximately 1,208 MW on a net ownership basis.

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 (“TSX”) under the symbol “ATP” and on the New York Stock Exchange (“NYSE”) 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, 2017. 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 June 30, 2018, the results of operations and comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017, and our cash flows for the six months ended June 30, 2018 and 2017 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.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Use of estimates

The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the 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, 2017. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Recently issued accounting standards

Adopted

In May 2017, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to address diversity in practice and cost and complexity of applying the guidance relating to stock compensation when there is a change to the terms or conditions of a share-based payment award. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. We adopted this guidance on January 1, 2018 and it did not have an impact 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. We adopted this guidance on January 1, 2018 and it was applied retrospectively to cash flows used in investing activities on the consolidated statements of cash flows for the six months ended June 30, 2017. As a result of adoption, cash flows used in investing activities was retrospectively decreased by $0.8 million for the six months ended June 30, 2017.

In October 2016, the FASB issued authoritative guidance, which amends existing guidance related to the recognition of current and deferred income 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. We adopted this guidance on January 1, 2018 and it did not have an impact on the consolidated financial statements.

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

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

identifiable cash flows and application of the predominance principle. We adopted this guidance on January 1, 2018 and it did not have an impact on the consolidated financial statements.

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity recognizes 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. We adopted this guidance on January 1, 2018 and it did not have an impact on the consolidated financial statements. Accordingly, we did not record a transition adjustment. The standard also requires new disclosures that 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. These disclosures can be found in Note 2, Revenue from contracts.

Issued

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

In February 2018, the FASB issued authoritative guidance to allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The guidance is effective for fiscal years beginning after December 15, 2018. We do not expect this to have a material impact to the consolidated financial statements upon adoption.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

2. Revenue from contracts

Accounting policy

We recognize energy sales revenue on a gross basis when electricity and steam are delivered and capacity revenue when capacity is provided under the terms of the related contracts. PPAs, steam purchase arrangements and energy services agreements are long‑term contracts with performance obligations to provide electricity, steam and capacity on a predetermined basis.

For certain PPAs determined to be operating leases, we recognize lease income consistent with the recognition of energy sales and capacity revenue. When energy is delivered and capacity is provided, we recognize lease income as a component of energy sales and capacity revenue.

Nature of goods and services

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, which have expiration dates ranging from June 30, 2019 to March 31, 2037, 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). 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 following is a description of principal activities from which we generate our revenue.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


Products and services	Nature, timing of satisfaction of performance obligations, and significant payment terms
Energy	Energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in our consolidated statements of operations. The price of energy could be contracted under PPAs at set prices or merchant sales based on market merchant price. Energy revenue is billed and paid on a monthly basis.
Energy capacity	Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at a negotiated contract price under the applicable PPAs for making installed generation capacity available in order to satisfy reliability requirements or merchant capacity sales based on the market price for such capacity. Energy capacity is billed and paid on a monthly basis.
Other revenue includes the following:
Steam energy and capacity	Steam revenue is recognized upon delivery to the customer. Steam capacity payments under the applicable PPAs are recognized as the amount billable under the respective PPA. Steam capacity is billed and paid on a monthly basis.
Waste heat	We generate electricity from excess steam provided by a nearby pipeline and its pumping station in the Canada segment. Waste heat is earned when it is generated and paid as a portion of monthly energy and capacity billing.
Enhanced dispatch contracts	We also bill and are paid for curtailment of energy generation under certain contractual arrangements with our offtaker. This revenue is recognized monthly under the terms of those agreements.
Ancillary and transmission services	We provide ancillary and transmission services to our customers under the terms of our PPAs. These services are billed and paid on a monthly basis.
Asset management and operation, operation and maintenance	We provide asset management and operation supervision to the Frederickson project, a facility that we jointly own with Puget Sound Energy. We also provide operation and maintenance services to several electric energy customers under the PPAs. All services are billed and paid on a monthly basis.

Disaggregation of revenue

We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. Each segment contains various power generation projects and performance obligations as described above. For more detailed information about reportable segments, see Note 13, Segment and geographical information. Revenue, receivables and contract liabilities by segment consists of following:

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


	Three Months Ended June 30, 2018
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	21.6	$	1.7	$	8.1	$	—	$	31.4
Energy capacity revenue		13.6		6.8		2.9		—		23.3
Steam energy and capacity revenue		0.4		—		—		—		0.4
Waste heat revenue		—		—				—		—
Enhanced dispatch contracts		—		—		6.4		—		6.4
Ancillary and transmission services		3.4		—		1.3		—		4.7
Asset management and operation		—		—		—		—		—
Miscellaneous revenue		—		(0.2)				0.2		—
		39.0		8.3		18.7		0.2		66.2


	Three Months Ended June 30, 2017
								Un-Allocated		Consolidated
		East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	24.4	$	7.8	$	7.8	$	—	$	40.0
Energy capacity revenue		12.4		13.3		2.6		—		28.3
Steam energy and capacity revenue		2.6		7.1		—		—		9.7
Waste heat revenue		—		—		0.1		—		0.1
Enhanced dispatch contracts		—		—		40.8		—		40.8
Ancillary and transmission services		1.0		—		4.1		—		5.1
Asset management and operation		—		—		—		0.3		0.3
Miscellaneous revenue		—		(0.3)		—		—		(0.3)
		40.4		27.9		55.4		0.3		124.0


	Six Months Ended June 30, 2018
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	47.0	$	6.8	$	16.0	$	—	$	69.8
Energy capacity revenue		24.9		12.7		5.8		—		43.4
Steam energy and capacity revenue		0.9		2.8		—		—		3.7
Waste heat revenue		—		—		0.1		—		0.1
Enhanced dispatch contracts		—		—		15.0		—		15.0
Ancillary and transmission services		7.8		—		6.3		—		14.1
Asset management and operation		—		—		—		—		—
Miscellaneous revenue		—		(0.4)		—		0.5		0.1
		80.6		21.9		43.2		0.5		146.2

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


	Six Months Ended June 30, 2017
								Un-Allocated		Consolidated
		East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	46.2	$	16.2	$	14.7	$	—	$	77.1
Energy capacity revenue		22.5		20.0		5.3		—		47.8
Steam energy and capacity revenue		5.9		15.6		—		—		21.5
Waste heat revenue		—		—		0.3		—		0.3
Enhanced dispatch contracts		—		—		65.0		—		65.0
Ancillary and transmission services		1.9		—		8.8		—		10.7
Asset management and operation		—		—		—		0.5		0.5
Miscellaneous revenue		—		(0.5)		—		—		(0.5)
		76.5		51.3		94.1		0.5		222.4

Contract balances

The following table provides information about receivables, contract assets and contract liabilities from contracts with customers.


	June 30,		December 31,
	2018		2017
Accounts receivables	$	25.3	$	52.7
Contract assets		—		—
Contract liabilities		0.6		1.0

Contract liabilities as of June 30, 2018 include a $0.4 million water license fee at Mamquam, which is a pass-through cost, and a $0.1 million capacity bonus accrual at Oxnard. Contract liabilities as of December 31, 2017 include recoverable wood fuel costs under the PPA and property tax at Williams Lake, which is proportionally estimated, pending receipt of an actual tax bill. The total $1.0 million was recognized as revenues from ancillary and transmission services in the first quarter of 2018.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

3. Changes in accumulated other comprehensive loss by component

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Foreign currency translation
Balance at beginning of period	$	(138.9)	$	(146.3)	$	(134.3)	$	(148.3)
Other comprehensive loss:
Foreign currency translation adjustments(1)		(2.9)		4.7		(7.5)		6.7
Balance at end of period	$	(141.8)	$	(141.6)	$	(141.8)	$	(141.6)
Pension
Balance at beginning of period	$	(1.6)	$	(0.8)	$	(1.6)	$	(0.9)
Other comprehensive loss:
Curtailment gain		—		—		—		0.1
Tax expense		—		—		—		—
Total Other comprehensive income before reclassifications, net of tax		—		—		—		0.1
Total amount reclassified from accumulated other comprehensive income, net of tax		—		—		—		—
Total other comprehensive income		—		—		—		0.1
Balance at end of period	$	(1.6)	$	(0.8)	$	(1.6)	$	(0.8)
Cash flow hedges
Balance at beginning of period	$	1.4	$	0.8	$	1.1	$	0.7
Other comprehensive income (loss):
Net change from periodic revaluations		—		(0.2)		0.4		(0.5)
Tax benefit (expense)		—		0.1		(0.2)		0.2
Total Other comprehensive (loss) income before reclassifications, net of tax		—		(0.1)		0.2		(0.3)
Net amount reclassified to earnings:
Interest rate swaps(2)		0.1		0.2		0.3		0.7
Tax expense		—		(0.1)		(0.1)		(0.3)
Total amount reclassified from accumulated other comprehensive loss, net of tax		0.1		0.1		0.2		0.4
Total other comprehensive income		0.1		—		0.4		0.1
Balance at end of period	$	1.5	$	0.8	$	1.5	$	0.8

⁽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.

⁽³⁾

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

4. Equity method investments in unconsolidated affiliates

The following summarizes the operating results for the three and six months ended June 30, 2018 and 2017, respectively, for our proportional ownership interest in equity method investments:


	Three Months Ended June 30,				Six Months Ended June 30,
Operating results	2018		2017		2018		2017
Revenue
Frederickson	$	4.7	$	4.8	$	9.8	$	10.1
Orlando Cogen, LP		15.2		12.9		29.7		26.1
Koma Kulshan Associates		0.8		0.8		1.0		1.1
Chambers Cogen, LP		9.6		10.3		22.8		22.6
Selkirk Cogen Partners, LP (1)		—		1.0		—		1.8
		30.3		29.8		63.3		61.7
Project expenses
Frederickson		3.4		7.5		6.6		11.9
Orlando Cogen, LP		7.6		7.8		14.6		14.9
Koma Kulshan Associates		0.3		0.3		0.6		0.6
Chambers Cogen, LP		7.5		9.2		17.1		18.3
Selkirk Cogen Partners, LP (1)		—		1.3		—		2.8
		18.8		26.1		38.9		48.5
Project other expense
Frederickson		—		—		—		—
Orlando Cogen, LP		—		—		—		—
Koma Kulshan Associates		—		—		—		—
Chambers Cogen, LP		(0.3)		(47.5)		(0.9)		(48.0)
Selkirk Cogen Partners, LP (1)		—		(10.6)		—		(10.6)
		(0.3)		(58.1)		(0.9)		(58.6)
Project income (loss)
Frederickson		1.3		(2.7)		3.2		(1.8)
Orlando Cogen, LP		7.6		5.1		15.1		11.2
Koma Kulshan Associates		0.5		0.5		0.4		0.5
Chambers Cogen, LP		1.8		(46.4)		4.8		(43.7)
Selkirk Cogen Partners, LP (1)		—		(10.9)		—		(11.6)
Equity in earnings (loss) of unconsolidated affiliates	$	11.2	$	(54.4)	$	23.5	$	(45.4)

Distributions from equity method investments		(20.7)		(13.5)		(27.3)		(17.2)
Deficit of earnings of equity method investments, net of distributions	$	(9.5)	$	(67.9)	$	(3.8)	$	(62.6)

⁽¹⁾

In November 2017, we sold our 17.7% interest in Selkirk.

On June 18, 2018, we purchased a 0.5% general partner interest in Concrete Hydro Partners L.P. (“Concrete”) for $1.1 million from Mt. Baker Corporation with cash on-hand. Prior to the purchase, we owned a 0.5% general partner interest and a 99.0% limited partner interest in Concrete; following the purchase, we own 100% of the entity. Concrete is the owner of a 50% limited partner interest in Koma Kulshan Associates, L.P. (“Koma”). As a result of the purchase, our ownership of Koma increased from 49.75% to 50.00%. With 50.00% percent ownership of Koma, we do not have financial control of the entity as the two owner parties have joint control and substantive participating rights through the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

structure of the partnership agreement. Accordingly, since we did not obtain control of the project, we continued to account for Koma under the equity method of accounting as of June 30, 2018. The $1.1 million purchase was accounted for as an additional equity method investment in Koma.

On July 27, 2018, we acquired the remaining 50% partnership interest in Koma from Covanta Energy Americas, Inc. (“Covanta”) for a purchase price of $11.8 million. As a result of this purchase, subsequent to the end of the second quarter, we own 100% of Koma and beginning in the third quarter will consolidate the project prospectively. In addition, we bought out the operation and maintenance contract held by Covanta for $0.3 million. We completed this acquisition because we view our hydro assets as having excellent near-term value and strong long-term prospects. We will have 100% ownership and operating control of a hydro project with a PPA that has a 19-year remaining term.

The purchase will be accounted for under the acquisition method of accounting. As of August 1, 2018, we are in the process of completing our purchase price allocation, which includes allocating the purchase price to both tangible and intangible assets and liabilities of Koma. The $12.1 million total purchase price was funded with cash on-hand. We assumed operation of the project from Covanta on the acquisition date of July 27, 2018.

5. Long‑term debt

Long‑term debt consists of the following:


	June 30,		December 31,
	2018		2017		Interest Rate
Recourse Debt:
Senior secured term loan facility, due 2023(1)	$	490.0	$	540.0	LIBOR(2)	plus	3.00	%
Senior unsecured notes, due June 2036 (Cdn$210.0)		159.5		167.4			5.95	%
Non-Recourse Debt:
Epsilon Power Partners term facility, due 2019 (3)		—		7.2	LIBOR	plus	3.125	%
Cadillac term loan, due 2025 (4)		22.5		24.0	LIBOR	plus	1.49	%
Other long-term debt		—		0.1	5.50	% -	6.70	%
Less: unamortized discount		(10.8)		(12.8)
Less: unamortized deferred financing costs		(8.6)		(10.1)
Less: current maturities		(78.0)		(99.5)
Total long-term debt	$	574.6	$	616.3

Current maturities consist of the following:


	June 30,		December 31,
	2018		2017		Interest Rate
Current Maturities:
Senior secured term loan facility, due 2023(1)	$	75.0	$	90.0	LIBOR(2)	plus	3.00	%
Epsilon Power Partners term facility, due 2019 (3)		—		6.5	LIBOR	plus	3.125	%
Cadillac term loan, due 2025 (4)		3.0		3.0	LIBOR	plus	1.49	%
Total current maturities	$	78.0	$	99.5

⁽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⁾

London Interbank Offered Rate (“LIBOR”) cannot be less than 1.00%. We have entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $457.7 million of the $490 million outstanding

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

aggregate borrowings under our senior secured term loan facility at June 30, 2018. See Note 8, Accounting for derivative instruments and hedging activities for further details. On April 19, 2018, the repricing of the $510 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 0.50% to LIBOR plus 3.00%.

⁽³⁾

In June 2018, we pre-paid the remaining $5.6 million principal amount originally due in 2018 and 2019.

⁽⁴⁾

We have entered into interest rate swap agreements to economically fix our exposure to changes in interest rates for this non-recourse debt. See Note 8, Accounting for derivative instruments and hedging activities, for further details.

⁽⁵⁾

6. Convertible debentures

Convertible debentures consist of the following:


	June 30,		December 31,
	2018		2017
6.00% Debentures due January 2025 (Series E) (Cdn $115.0 million)		87.3		—
5.75% Debentures due June 2019 (Series C)		—		42.5
6.00% Debentures due December 2019 (Series D) (Cdn $24.7 million)		18.8		64.5
Less: Unamortized deferred financing costs		(4.7)		(1.6)
Less: Unamortized discount		(4.4)		—
Total convertible debentures	$	97.0	$	105.4

On January 29, 2018, we closed the sale of our offering (the “Series E Debenture Offering”) of Cdn$100 million aggregate principal amount of 6.00% Series E convertible unsecured subordinated debentures (the “Series E Debentures”). We also granted the underwriters the option to purchase up to an additional Cdn$15 million aggregate principal amount of Series E Debentures at any time up to 30 days after the date of closing of the Series E Debenture Offering to cover over-allotments. The underwriters exercised that option for the full Cdn$15 million aggregate principal amount on February 2, 2018.

On the initial closing date, we received net proceeds from the Series E Debentures Offering, after deducting the underwriting fee and expenses, of approximately Cdn$94.7 million. We received an additional Cdn$14.4 million of net proceeds from the exercise of the over-allotment option. On January 29, 2018, we issued a notice to redeem all of the $42.5 million remaining principal amount of 5.75% Series C convertible unsecured subordinated debentures due June 2019 (the “Series C Debentures”) with the use of a portion of the proceeds from the Series E Debenture Offering. On February 2, 2018, we issued a notice to redeem Cdn$56.2 million principal amount of the 6.00% Series D extendible convertible unsecured subordinated debentures due December 2019 (the “Series D Debentures”) with the remaining proceeds from the Series E Debentures Offering. After the partial redemption, Cdn$24.7 million ($18.8 million) aggregate principal amount of the Series D Debentures remains outstanding.

The Series E Debentures have a maturity date of January 31, 2025. The Series E Debentures bear interest at a rate of 6.00% per year, and are convertible into our common shares at an initial conversion rate of approximately 238.0952 common shares per Cdn$1,000 principal amount, representing a conversion price of Cdn$4.20 per common share.

We assessed the conversion option of the Series E Debentures and determined it should be separated from the host instrument and accounted for as an embedded derivative liability as the conversion option is in a currency different from our functional currency. Changes in the fair value of the conversion option derivative are recorded in the consolidated statements of operation. The conversion option derivative was initially measured at fair value ($4.7 million), with the host contract carried at a value equal to the difference between the carrying value of the Series E Debenture and the fair value of the derivative. Accordingly, no gain or loss was recorded on the initial measurement of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

the derivative. The fair value of the conversion option derivative was $2.3 million as of June 30, 2018. The portion of the proceeds allocated to the separated derivative also created a discount of $4.7 million, which will be amortized to interest expense over the maturity period of the Series E Debentures. For additional information, see Note 8, Accounting for derivative instruments and hedging activities.

7. Fair value of financial instruments

The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of June 30, 2018 and December 31, 2017. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.


	June 30, 2018
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	80.8	$	—	$	—	$	80.8
Restricted cash		1.9		—		—		1.9
Derivative instruments asset		—		8.5		—		8.5
Total	$	82.7	$	8.5	$	—	$	91.2
Liabilities:
Derivative instruments liability	$	—	$	21.5	$	2.3	$	23.8
Total	$	—	$	21.5	$	2.3	$	23.8


	December 31, 2017
	Level 1		Level 2		Level 3		Total
Assets:
Cash and cash equivalents	$	78.7	$	—	$	—	$	78.7
Restricted cash		6.2		—		—		6.2
Derivative instruments asset		—		5.5		—		5.5
Total	$	84.9	$	5.5	$	—	$	90.4
Liabilities:
Derivative instruments liability	$	—	$	24.3	$	—	$	24.3
Total	$	—	$	24.3	$	—	$	24.3

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

We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of June 30, 2018, the credit valuation adjustments resulted in a $1.9 million net increase in fair value, which consists of a $0.1 million pre‑tax gain in other comprehensive income and a $1.8 million gain in change in fair value of derivative instruments. As of December 31, 2017, the credit valuation adjustments resulted in a $2.2 million net increase in fair value, which consists of a $0.2 million pre‑tax gain in other comprehensive income and a $2.0 million gain in change in fair value of derivative instruments.

The conversion option derivative for the Series E Debentures is classified within Level 3 of the fair value hierarchy. The significant unobservable inputs used in developing fair value include the volatility of our common shares

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

and the fair value of the host contract, which is derived from recent similar convertible debenture offerings from peer companies. A discounted cash flow valuation technique is utilized to calculate to fair value of the conversion option derivative.

The following table reconciles, for the three and six months ended June 30, 2018, the beginning and ending balances for the conversion option derivative that is recognized at fair value in the consolidated financial statements, using significant unobservable inputs:


	Fair value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended		Six months ended
	June 30, 2018		June 30, 2018

Beginning balance	$	2.6	$	—
Total gains - realized / unrealized		(0.3)		2.3
Ending balance as of June 30, 2018	$	2.3	$	2.3

For cash and cash equivalents, accounts and other receivables, accounts payable and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

8. Accounting for derivative instruments and hedging activities

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

Gas purchase and sale agreements

We have a gas purchase agreement at our Nipigon project that expires on December 31, 2022 under which we purchase a minimum of 6,500 Gigajoules (“Gj”) of natural gas per day at a price of Cdn$4.57 per Gj. We also entered into a gas sales agreement for our Nipigon project under which we sell 6,500 Gj of natural gas per day at a price of Cdn$2.75 that expires on October 31, 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.

We have also entered into various natural gas sales and purchase agreements for approximately 700,000 Mmbtu to effectively mitigate seasonal fluctuation of future natural gas price at Morris from September through February 2019. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2018. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Natural gas swaps

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

We have entered into various natural gas swaps to effectively fix the price of 14.1 million Mmbtu of future natural gas purchases at our Orlando project, which is approximately 90% of the remaining expected natural gas purchases at the project in 2018 and 100% of our share of the expected natural gas purchases in 2019 through 2021. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2018. 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. At June 30, 2018, these agreements totaled $457.7 million notional amount of the remaining $490.0 million aggregate principal amount of borrowings under the senior secured term loan facility (“Term Loan Facility”). These interest rate swap agreements expire at various dates through March 31, 2020. Borrowings under the $700.0 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 3.00%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00%, resulting in a minimum of a 4.00% all-in rate on the Term Loan Facility for the non-swapped portion of the remaining principal amount. The weighted average rate of these swap agreements is 1.34%, resulting in an all-in rate of approximately 4.34% for $457.7 million of the Term Loan Facility. In January 2018, APLP Holdings entered into additional interest rate swap agreements. For the period beginning June 30, 2018 through September 30, 2019, we mitigated exposure to changes in interest rates for $100 million notional amount at a one-month LIBOR fixed rate of 2.18% and for the period beginning October 1, 2019 through December 31, 2020, for $200 million notional amount at a one-month LIBOR fixed rate of 2.42%.

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 income (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 due June 23, 2036 (“MTNs”). 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 July 2017, we entered into foreign exchange forward contracts to sell a total of Cdn$10 million at an exchange rate of 1.2481 in three tranches of Cdn$3.3 million each. One tranche of Cdn$3.3 million remains and will settle in December 2018. In July 2017, we also entered into foreign exchange forward contracts to sell a total of Cdn$10

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

million at an exchange rate of 1.2943. One tranche of Cdn$2.0 million remains and will settle 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 June 30, 2018.

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 June 30, 2018 and December 31, 2017:


		June 30,	December 31,
	Units	2018	2017
Natural gas swaps	Natural Gas (Mmbtu)	14.1	9.9
Gas purchase agreements	Natural Gas (Gigajoules)	9.9	9.9
Interest rate swaps	Interest (US$)	664.6	412.6
Foreign currency forward contracts	Dollars (Cdn$)	10.3	25.0

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:


	June 30, 2018
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.4
Interest rate swaps long-term		—		1.0
Total derivative instruments designated as cash flow hedges		—		1.4
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		5.2		—
Interest rate swaps long-term		2.6		—
Natural gas swaps current		—		0.1
Natural gas swaps long-term		—		1.4
Gas purchase agreements current		0.2		3.2
Gas purchase agreements long-term		—		15.4
Convertible debenture conversion option		—		2.3
Foreign currency forward contracts current		0.5		—
Total derivative instruments not designated as cash flow hedges		8.5		22.4
Total derivative instruments	$	8.5	$	23.8

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


	December 31, 2017
	Derivative		Derivative
	Assets		Liabilities
Derivative instruments designated as cash flow hedges:
Interest rate swaps current	$	—	$	0.6
Interest rate swaps long-term		—		1.5
Total derivative instruments designated as cash flow hedges		—		2.1
Derivative instruments not designated as cash flow hedges:
Interest rate swaps current		2.7		—
Interest rate swaps long-term		2.8		—
Natural gas swaps current		—		0.8
Natural gas swaps long-term		—		0.2
Gas purchase agreements current		—		2.9
Gas purchase agreements long-term		—		18.2
Foreign currency forward contracts current		—		0.1
Total derivative instruments not designated as cash flow hedges		5.5		22.2
Total derivative instruments	$	5.5	$	24.3

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Accumulated other comprehensive income

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


	Interest Rate
Three Months Ended June 30, 2018	Swaps
Accumulated OCI balance at March 31, 2018	$	1.4
Change in fair value of cash flow hedges		—
Realized from OCI during the period		0.1
Accumulated OCI balance at June 30, 2018	$	1.5

	Interest Rate
Three Months Ended June 30, 2017	Swaps
Accumulated OCI balance at March 31, 2017	$	0.8
Change in fair value of cash flow hedges		(0.1)
Realized from OCI during the period		0.1
Accumulated OCI balance at June 30, 2017	$	0.8

	Interest Rate
Six Months Ended June 30, 2018	Swaps
Accumulated OCI balance at January 1, 2018	$	1.1
Change in fair value of cash flow hedges		0.2
Realized from OCI during the period		0.2
Accumulated OCI balance at June 30, 2018	$	1.5

	Interest Rate
Six Months Ended June 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		0.4
Accumulated OCI balance at June 30, 2017	$	0.8

Impact of derivative instruments on the consolidated statements of operations

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



	Classification of loss (gain)	Three Months Ended June 30,				Six Months Ended June 30,
	recognized in income	2018		2017		2018		2017
Gas purchase agreements	Fuel	$	0.8	$	2.4		1.7	$	4.9
Natural gas swaps	Fuel		0.2		(0.4)		0.8		(0.5)
Interest rate swaps	Interest, net		(1.1)		0.8		(1.1)		1.7

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


	Classification of gain (loss)	Three Months Ended June 30,				Six Months Ended June 30,
	recognized in income	2018		2017		2018		2017
Natural gas swaps	Change in fair value of derivatives	$	(0.6)	$	(0.8)	$	(0.5)	$	(0.6)
Gas purchase agreements	Change in fair value of derivatives		0.3		(0.8)		1.6		(2.9)
Interest rate swaps	Change in fair value of derivatives		0.1		(1.1)		2.4		(0.4)
		$	(0.2)	$	(2.7)		3.5		(3.9)
Convertible debenture conversion option	Other income, net		(0.2)		—		(2.3)		—
Foreign currency forwards	Foreign exchange loss	$	(0.1)	$	(0.3)	$	(0.6)	$	(0.5)

9. Income taxes


	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Current income tax expense	$	1.1	$	1.4	$	2.2	$	2.3
Deferred income tax (benefit) expense		(0.2)		(23.7)		2.0		(24.9)
Total income tax expense (benefit), net	$	0.9	$	(22.3)	$	4.2	$	(22.6)

For the three and six months ended June 30, 2018 and 2017

Income tax expense for the three months ended June 30, 2018 was $0.9 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $0.5 million. On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was signed into law, making significant changes to the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, which have been reflected in our 2017 year-end financials, limitation on the deduction of net business interest expense, and base erosion and anti-abuse tax. Based on estimates as of the date of this filing, the interest expense limitation and base erosion and anti-abuse tax will not have a material impact on cash taxes. The primary items impacting the tax rate for the three months ended June 30, 2018 were $0.3 million relating to foreign exchange and $0.2 million of other permanent differences. These items were partially offset by a net decrease to our valuation allowances of $0.1 million, consisting of $0.1 million decreases in Canada due to income and no changes in the United States for the period.

Income tax benefit for the three months ended June 30, 2017 was $22.3 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $11.0 million. The primary item increasing the tax rate for the three months ended June 30, 2017 was $0.2 million relating to return to provision adjustments. This item was partially offset by $8.4 million relating to operating in higher tax rate jurisdictions, $2.6 million related to a net decrease to our valuation allowances in Canada due to income and $0.6 million relating to foreign exchange.

Income tax expense for the six months ended June 30, 2018 was $4.2 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $5.0 million. The primary items impacting the tax rate for the six months ended June 30, 2018 were a net increase to our valuation allowances of $0.8 million, consisting of $0.8 million of increases in Canada related to losses and no changes in the United States for the period. In addition, the rate was further impacted by $0.3 million of taxes and $0.3 million of other permanent differences. These

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

items were partially offset by $1.3 million related to capital loss on intercompany notes and $0.9 million relating to changes in tax rates.

Income tax benefit for the six months ended June 30, 2017 was $22.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26% was $11.2 million. The primary items impacting the tax rate for the six months ended June 30, 2017 were $0.3 million relating to return to provision adjustments. These items were offset by $8.7 million relating to operating in higher tax rate jurisdictions, $1.9 million related to a net decrease to the Company's valuation allowances in Canada due to income, $1.0 million relating to foreign exchange and $0.1 million of other permanent differences.

As of June 30, 2018, we have recorded a valuation allowance of $152.2 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 U.S. and in Canada and available tax planning strategies.

10. Equity compensation plans

Long‑term incentive plan (“LTIP”)

The following table summarizes the changes in outstanding LTIP notional units during the six months ended June 30, 2018:


		Grant Date
		Weighted-Average
	Units	Fair Value per Unit
Outstanding at December 31, 2017	2,884,574		2.22
Granted	2,483,237		2.02
Vested and redeemed	(1,216,252)		2.24
Outstanding at June 30, 2018	4,151,559	$	2.09

Cash payments made for vested notional units for the six months ended June 30, 2018 and 2017 were $0.8 million and $0.7 million, respectively. Compensation expense for LTIP and Transition Equity Participation Agreement notional shares was $1.0 million and $1.5 million for the three and six months ended June 30, 2018, respectively, and $0.9 million and $1.7 million for the three and six months ended June 30, 2017, respectively.

Transition Equity Participation Agreement

We also have 539,904 transition notional shares outstanding at June 30, 2018 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).

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

11. Basic and diluted earnings (loss) per share

Basic earnings (loss) per share is calculated by dividing net income (loss) attributable to Atlantic Power Corporation by the weighted average common shares outstanding during their respective periods. Shares issued and shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings (loss) per share is computed in a manner consistent with that of basic earnings (loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. 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 earnings (loss) per share 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. The outstanding equity compensation for non-vested LTIP and Transition Equity Participation Agreement notional shares are not considered outstanding for purposes of computing basic earnings (loss) per share. However, these instruments are included in the denominator for purposes of computing diluted earnings (loss) per share under the treasury stock method.

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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 calculation of basic and diluted (loss) earnings per share for the three and six months ended June 30, 2018 and 2017:


	Three Months Ended June 30,				Six Months Ended June 30,
Basic	2018		2017		2018		2017
Numerator:
Net (loss) income attributable to Atlantic Power Corporation	$	(0.6)	$	(21.9)	$	15.2	$	(24.6)
Denominator:
Weighted average basic shares outstanding		112.4		115.2		113.6		115.0
Basic (loss) earnings per share attributable to Atlantic Power Corporation	$	(0.01)	$	(0.19)	$	0.13	$	(0.21)
Diluted
Numerator:
Net (loss) income attributable to Atlantic Power Corporation	$	(0.6)	$	(21.9)	$	15.2	$	(24.6)
Add: convertible debenture interest expense		—		—		2.2		—
		(0.6)		(21.9)		17.4		(24.6)
Denominator:
Weighted average basic shares outstanding		112.4		115.2		113.6		115.0
Convertible debentures		—		—		26.5		—
Share-based compensation		—		—		—		—
		112.4		115.2		140.1		115.0
Diluted (loss) earnings per share attributable to Atlantic Power Corporation	$	(0.01)	$	(0.19)	$	0.13	$	(0.21)

The following table summarizes our outstanding instruments that are anti-dilutive and were not included in the computation of our diluted (loss) earnings per share:


	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Share-based compensation		2.6		2.6		5.4		2.6
Convertible debentures		29.1		8.1		—		8.1
Total		31.7		10.7		5.4		10.7

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

12. Equity

The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary company and total equity for the six months ended June 30, 2018 and 2017:


	Six months ended June 30, 2018
	Total Atlantic		Preferred shares
	Power Corporation		issued by a subsidiary
	Shareholders’ Equity		company		Total Equity
Balance at January 1, 2018	$	(18.4)	$	215.2	$	196.8
Net income (loss)		15.2		(0.1)		15.1
Realized and unrealized gain on hedging activities, net of tax		0.4		—		0.4
Foreign currency translation adjustment		(7.5)		—		(7.5)
Common share repurchases		(9.2)		—		(9.2)
Preferred share repurchases		—		(4.5)		(4.5)
Share-based compensation		1.1		—		1.1
Dividends declared on preferred shares of a subsidiary company		—		(4.3)		(4.3)
Balance at June 30, 2018	$	(18.4)	$	206.3	$	187.9


	Six months ended June 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		(24.6)		4.3		(20.3)
Realized and unrealized gain on hedging activities, net of tax		0.1		—		0.1
Foreign currency translation adjustment		6.7		—		6.7
Defined benefit plan, net of tax		0.1		—		0.1
Share-based compensation		1.1		—		1.1
Dividends declared on preferred shares of a subsidiary company		—		(4.3)		(4.3)
Balance at June 30, 2017	$	48.0	$	221.3	$	269.3

Share Repurchase Program

On December 29, 2016, we commenced 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. We repurchased a cumulative 0.1 million common shares at a total cost of $0.2 million before its expiration on December 28, 2017. Repurchases and retirement of common shares are recorded to common shares on the consolidated balance sheets.

On December 29, 2017, we commenced a new NCIB for our Series C and Series D Debentures, our common shares and for each series of the preferred shares of APPEL. The new NCIBs expire on December 28, 2018 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the new NCIBs. Under the new NCIBs, we may purchase up to a total of 11,308,946 common shares based on 10% of our public float as of

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

December 15, 2017 and we are limited to daily purchases of 11,789 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. All purchases made under the new NCIBs will be made through the facilities of the TSX or other Canadian designated exchanges and published marketplaces and in accordance with the rules of the TSX at market prices prevailing at the time of purchase. Common share purchases under the NCIBs may also be made on the NYSE in compliance with Rule 10b-18 under the Exchange Act or other designated exchanges and published marketplaces in the U.S. in accordance with applicable regulatory requirements. The ability to make certain purchases through the facilities of the NYSE is subject to regulatory approval. For the six months ended June 30, 2018, we repurchased and cancelled 4.3 million shares at a cost of $9.2 million.

On June 21, 2018, we amended the NCIBs to increase the number of 4.85% Cumulative Redeemable Preferred Shares, Series 1 (“Series 1 Preferred Shares”) that we may purchase to 475,000, representing approximately 10% of the 4,750,000 preferred shares public float as of December 15, 2017; increase the number of Cumulative Rate Reset Preferred Shares, Series 2 (“Series 2 Preferred Shares”) that we may purchase to 233,609, representing approximately 10% of the 2,338,094 preferred shares public float as of December 15, 2017; and increase the number of Cumulative Floating Rate Preferred Shares, Series 3 (“Series 3 Preferred Shares”) that we may purchase to 164,790, representing approximately 10% of the 1,661,906 preferred shares public float as of December 15, 2017. Daily repurchases are not affected by the amendment and each series will be limited to 1,000 preferred shares daily, other than block purchase exemptions.

Under the NCIBs, we also repurchased and cancelled 237,500 of our Series 1 Preferred Shares and 123,095 of our Series 3 Preferred Shares at a total cost of $4.5 million, resulting in a $4.4 million gain recorded in net (loss) income attributable to preferred shares of a subsidiary company in the six months ended June 30, 2018.

13. 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).

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

A reconciliation of Project Adjusted EBITDA to net income (loss) for the three and six months ended June 30, 2018 and 2017 is included in the tables below:


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Three Months Ended June 30, 2018
Project revenues	$	39.0	$	8.3	$	18.7	$	0.2	$	66.2
Segment assets		610.5		167.1		197.6		92.6		1,067.8
Project Adjusted EBITDA	$	31.2	$	(0.7)	$	9.0	$	0.3	$	39.8
Change in fair value of derivative instruments		0.5		—		(0.2)		(0.1)		0.2
Depreciation and amortization		11.4		5.6		8.0		0.1		25.1
Interest, net		0.9		—		—		—		0.9
Project income (loss)		18.4		(6.3)		1.2		0.3		13.6
Administration		—		—		—		6.2		6.2
Interest expense, net		—		—		—		11.1		11.1
Foreign exchange gain		—		—		—		(5.4)		(5.4)
Other income, net		—		—		—		(0.2)		(0.2)
Income (loss) before income taxes		18.4		(6.3)		1.2		(11.4)		1.9
Income tax expense		—		—		—		0.9		0.9
Net income (loss)	$	18.4	$	(6.3)	$	1.2	$	(12.3)	$	1.0


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Three Months Ended June 30, 2017
Project revenues	$	40.4	$	27.9	$	55.4	$	0.3	$	124.0
Segment assets		688.5		299.3		281.9		104.4		1,374.1
Project Adjusted EBITDA	$	29.1	$	10.6	$	45.2	$	0.5	$	85.4
Change in fair value of derivative instruments		0.7		—		0.9		1.0		2.6
Depreciation and amortization		11.4		10.0		13.2		0.1		34.7
Interest, net		2.6		(0.1)		—		—		2.5
Impairment		57.7		—		—		—		57.7
Project (loss) income		(43.3)		0.7		31.1		(0.6)		(12.1)
Administration		—		—		—		5.7		5.7
Interest expense, net		—		—		—		18.4		18.4
Foreign exchange loss		—		—		—		5.9		5.9
(Loss) income before income taxes		(43.3)		0.7		31.1		(30.6)		(42.1)
Income tax benefit		—		—		—		(22.3)		(22.3)
Net (loss) income	$	(43.3)	$	0.7	$	31.1	$	(8.3)	$	(19.8)

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Six Months Ended June 30, 2018
Project revenues	$	80.6	$	21.9	$	43.2	$	0.5	$	146.2
Segment assets		610.5		167.1		197.6		92.6		1,067.8
Project Adjusted EBITDA	$	64.4	$	5.4	$	23.2	$	0.2	$	93.2
Change in fair value of derivative instruments		0.2		—		(1.4)		(2.4)		(3.6)
Depreciation and amortization		23.2		13.6		16.1		0.2		53.1
Interest, net		1.9		—		—		—		1.9
Project income (loss)		39.1		(8.2)		8.5		2.4		41.8
Administration		—		—		—		12.2		12.2
Interest expense, net		—		—		—		26.1		26.1
Foreign exchange gain		—		—		—		(13.6)		(13.6)
Other income, net		—		—		—		(2.2)		(2.2)
Net income (loss) before income taxes		39.1		(8.2)		8.5		(20.1)		19.3
Income tax expense		—		—		—		4.2		4.2
Net income (loss)	$	39.1	$	(8.2)	$	8.5	$	(24.3)	$	15.1


							Un-Allocated
	East U.S.		West U.S.		Canada		Corporate		Consolidated
Six Months Ended June 30, 2017
Project revenues	$	76.5	$	51.3	$	94.1	$	0.5	$	222.4
Segment assets		688.5		299.3		281.9		104.4		1,374.1
Project Adjusted EBITDA	$	56.2	$	19.8	$	72.8	$	0.5	$	149.3
Change in fair value of derivative instruments		1.3		—		4.1		(1.6)		3.8
Depreciation and amortization		22.7		19.8		26.4		0.4		69.3
Interest, net		5.3		—		—		—		5.3
Impairment		57.7		—		—		—		57.7
Project income (loss)		(30.8)		—		42.3		1.7		13.2
Administration		—		—		—		12.1		12.1
Interest expense, net		—		—		—		35.7		35.7
Foreign exchange loss		—		—		—		8.3		8.3
Net (loss) income before income taxes		(30.8)		—		42.3		(54.4)	$	(42.9)
Income tax benefit		—		—		—		(22.6)		(22.6)
Net (loss) income	$	(30.8)	$	—	$	42.3	$	(31.8)	$	(20.3)

The table below provides information, by country, about our consolidated operations for each of the three and six months ended June 30, 2018 and 2017 and Property, Plant & Equipment as of June 30, 2018 and December 31, 2017, 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				Project Revenue				Property, Plant and
	Three Months Ended				Six Months Ended				Equipment, net of
	June 30,				June 30,				accumulated depreciation
	2018		2017		2018		2017		June 30, 2018		December 31, 2017
United States	$	47.5	$	68.6	$	103.0	$	128.3	$	409.8	$	426.2
Canada		18.7		55.4		43.2		94.1		163.3		176.1
Total	$	66.2	$	124.0	$	146.2	$	222.4	$	573.1	$	602.3

Table of Contents

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Concentration risk

Niagara Mohawk, BC Hydro, Georgia Power Company and Equistar Chemicals, LP provided 16.9%, 13.0%, 11.6% and 11.6%, respectively, of total consolidated revenues for the three months ended June 30, 2018. Independent Electricity System Operator (“IESO”), Ontario Electricity Financial Corporation (“OEFC”) and Niagara Mohawk provided 17.8%, 17.8% and 11.8%, respectively, of total consolidated revenues for the three months ended June 30, 2017. Niagara Mohawk, BC Hydro, Equistar Chemicals, LP and IESO provided 16.3%, 14.2%, 11.5% and 10.2%, respectively, of total consolidated revenues for the six months ended June 30, 2018. IESO, Niagara Mohawk and OEFC provided 20.9%, 12.1% and 11.5%, respectively, of total consolidated revenues for the six months ended June 30, 2017. IESO and OEFC purchase electricity from the Calstock and Nipigon projects in the Canada segment, Niagara Mohawk purchases electricity from the Curtis Palmer project in the East U.S. segment, Equistar Chemicals, LP purchases electricity from the Morris 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.

14. 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 June 30, 2018.

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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, 2017 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, 2017 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, long‑lived assets or equity method investments;

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 is an independent power producer that owns power generation assets in nine states in the United States and two provinces in Canada. Our power generation projects, which are diversified by geography, fuel type, dispatch profile and offtaker, sell electricity to utilities and other large customers predominantly under long‑term PPAs, which seek to minimize exposure to changes in commodity prices. As of June 30, 2018, the Company’s portfolio consisted of twenty-two projects with an aggregate electric generating capacity of approximately 1,793 MW on a gross ownership basis and approximately 1,440 MW on a net ownership basis. Eighteen of the projects are majority‑owned and operated by the Company. At June 30, 2018, three of our Ontario projects were not in operation, two because of contract expirations on December 31, 2017, and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence with commercial operation of the plant in the fourth quarter of 2018. In early February 2018, our three plants in San Diego, totaling 112 MW on a gross and net ownership basis, ceased operations. The sixteen projects in operation at June 30, 2018 have generating capacity of approximately 1,561 MW on a gross ownership basis and approximately 1,208 MW on a net ownership basis.

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 June 30, 2019 to March 31, 2037. 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 (twelve of which are currently in operation). 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

Koma Kulshan Acquisition

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our ownership of Koma increased from 49.75% to 50.00%. The $1.1 million purchase was accounted for as an additional equity method investment in Koma.

On July 27, 2018, we acquired the remaining 50% partnership interest in Koma from Covanta Energy Americas, Inc. (“Covanta”) for a purchase price of $11.8 million. As a result of the purchase, we own 100% of Koma and will consolidate the project prospectively from the acquisition date. In addition, we bought out the operation and maintenance contract held by Covanta for $0.3 million.

Share buybacks

Under the new NCIB, we repurchased and cancelled approximately 1.3 million shares at a cost of $2.8 million during the three months ended June 30, 2018, bringing our total purchases for the six months ended June 30, 2018 to approximately 4.3 million shares at a cost of $9.2 million.

We also repurchased and cancelled 40,000 of our Series 3 Preferred Shares for Cdn$0.7 million in the three months ended June 30, 2018. We previously purchased and cancelled 237,500 of our Series 1 Preferred Shares and 83,095 of our Series 3 Preferred Shares for a total payment of Cdn$5.1 million in the three months ended March 31, 2018.

OUR POWER PROJECTS

The table below outlines our portfolio of power generating assets in operation as of August 1, 2018, 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 rating 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.

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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(2)

Illinois

Natural Gas

177

100.00

120

Merchant

N/A

Equistar Chemicals, LP

December, 2034

BBB+(3)

Cadillac

Michigan

Biomass

100.00

Consumers Energy

June 2028

BBB+

Chambers(1)

New Jersey

Coal

262

40.00

Atlantic City Electric(4)

March 2024

BBB+

Chemours Co.

March 2024

Kenilworth

New Jersey

Natural Gas

100.00

Merck & Co., Inc.

September 2019 (5)

Curtis Palmer

New York

Hydro

100.00

Niagara Mohawk Power Corporation

December 2027 (6)

A–

West U.S. Segment

Oxnard

California

Natural Gas

100.00

Southern California Edison

April 2020 (7)

BBB+

Manchief (8)

Colorado

Natural Gas

300

100.00

300

Public Service Company of Colorado

April 2022

A–

Frederickson(1)

Washington

Natural Gas

250

50.15

Benton Co. PUD

August 2022

AA–

Grays Harbor PUD

August 2022

A+

Franklin Co. PUD

August 2022

A+

Koma Kulshan(9)

Washington

Hydro

100.00

Puget Sound Energy

March 2037

BBB

Canada Segment

Mamquam(10)

British Columbia

Hydro

100.00

British Columbia Hydro and Power Authority

September 2027

AAA

Moresby Lake

British Columbia

Hydro

100.00

British Columbia Hydro and Power Authority

August 2022

AAA

Williams Lake

British Columbia

Biomass

100.00

British Columbia Hydro and Power Authority

June 2019

AAA

Calstock

Ontario

Biomass

100.00

Ontario Electricity Financial Corporation

June 2020

Nipigon

Ontario

Natural Gas

100.00

Independent Electricity System Operator

December 2022 (11)

⁽¹⁾

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

⁽²⁾

Equistar has an option to purchase Morris that is exercisable in December 2020 and in December 2027.

⁽³⁾

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

⁽⁴⁾

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.

⁽⁵⁾

Merck has two additional successive one-year extension options.

⁽⁶⁾

The Curtis Palmer PPA expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. From January 6, 1995 through June 30, 2018, the facility has generated 7,511 GWh under its PPA. Based on cumulative generation to date, we expect the PPA to expire prior to December 2027.

⁽⁷⁾

Oxnard’s steam sales agreement expires in February 2020.

⁽⁸⁾

Public Service Company of Colorado has an option to purchase Manchief that is exercisable in May 2020 and in May 2021.

⁽⁹⁾

In June 2018, we purchased an additional 0.25% ownership of Koma Kulshan and in July 2018, we purchased the remaining 50%, bringing our total ownership to 100%.

⁽¹⁰⁾

BC Hydro has an option to purchase Mamquam that is exercisable in November 2021.

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⁽¹¹⁾

In December 2017, we entered into a long-term enhanced dispatch contract with the IESO for Nipigon for the period from November 1, 2018 through December 31, 2022. As a result, the PPA will be terminated effective October 31, 2018. The long-term enhanced dispatch contract provides for Nipigon to receive monthly capacity-type payments based on the original PPA, with adjustment for operational savings that will be shared with the IESO. In addition, the project will function as a market participant and earn energy revenues for those periods during which it operates.

The following table below outlines our power generating assets under contract, but not currently in operation:

Economic

Power

Customer Credit

Project

Location

Type

Interest

Net MW

Primary Electric Purchasers

Contract Expiry

Rating (S&P)

Canada Segment

Tunis

Ontario

Natural Gas

100.00

Independent Electricity System Operator

(1)

⁽¹⁾

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 during the fourth quarter of 2018. The 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.

The following table outlines our power generating assets not currently in operation or under contract:

Economic

Power

Customer Credit

Project

Location

Type

Interest

Net MW

Primary Electric Purchasers

Contract Expiry

Rating (S&P)

West U.S. Segment

Naval Station

California

Natural Gas

100.00

N/A

(1)

N/A

Naval Training Center

California

Natural Gas

100.00

N/A

(1)

N/A

North Island

California

Natural Gas

100.00

N/A

(1)

N/A

Canada Segment

Kapuskasing

Ontario

Natural Gas

100.00

N/A

North Bay

Ontario

Natural Gas

100.00

N/A

⁽¹⁾

Although our original PPAs with San Diego Gas & Electric (“SDG&E”) for these three projects were not scheduled to expire until December 2019, we ceased operations at these projects in February 2018, when our land use agreements with the U.S. Navy expired. In July 2017, we executed amendments to the existing PPAs with SDG&E for Naval Station, North Island and Naval Training Center (“NTC”), which provided for termination of the existing PPAs, and we entered into new seven-year Power Purchase Tolling Agreements (“PPTAs”) with SDG&E for the Naval Station and North Island projects. The PPTAs are subject to certain significant conditions, including retaining the right to operate on the Navy properties beyond February 2018 (“site control”). We also entered into Resource Adequacy (“RA”) contracts with SDG&E for all three projects. The RA contracts also require us to obtain site control. We obtained approval of the California Public Utilities Commission (“CPUC”) for the aforementioned PPTAs, termination of the existing PPAs and the RA contracts on March 1, 2018. As a result of the approval, the existing PPAs with SDG&E for Naval Station, North Island and Naval Training Center were terminated on March 1, 2018. As of August 1, 2018, we have not obtained site control at any of the three plant sites. In September 2017, we entered into a seven-year PPA with Southern California Edison for our NTC project that would commence in January 2019. The PPA is a sale of RA capacity and a toll of the energy production resulting from offering the resource to the California Independent System Operator. However, in July 2018, the CPUC rejected this PPA. Accordingly, we are proceeding with plans to decommission NTC.

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Consolidated Overview and Results of Operations

Performance highlights

The following table provides a summary of our consolidated results of operations for the three and six months ended June 30, 2018 and 2017, which are analyzed in greater detail below:


	Three months ended				Six months ended
	June 30,				June 30,
	2018		2017		2018		2017
Project revenue	$	66.2	$	124.0	$	146.2	$	222.4
Project income (loss)	$	13.6	$	(12.1)	$	41.8	$	13.2
Net (loss) income attributable to Atlantic Power Corporation	$	(0.6)	$	(21.9)	$	15.2	$	(24.6)
(Loss) income per share attributable to Atlantic Power Corporation—basic	$	(0.01)	$	(0.19)	$	0.13	$	(0.21)
(Loss) income per share attributable to Atlantic Power Corporation—diluted	$	(0.01)		(0.19)		0.13		(0.21)
Project Adjusted EBITDA(1)	$	39.8	$	85.4	$	93.2	$	149.3

⁽¹⁾

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

Project revenue decreased by $57.8 million to $66.2 million in the three months ended June 30, 2018 from $124.0 million in the three months ended June 30, 2017. The primary drivers of the decrease are as follows:

OEFC settlement – we recorded $24.7 million of project revenue related to the OEFC settlement in the comparable 2017 period at our North Bay, Kapuskasing and Tunis projects and did not receive a settlement in 2018;

San Diego projects – the Naval Station, North Island and NTC projects ceased operations in February 2018. This resulted in a $19.9 million decrease in project revenue;

Enhanced dispatch contracts – the enhanced dispatch contracts with the IESO for Kapuskasing and North Bay expired in December 2017, which resulted in a $10.4 million decrease in project revenue; and

Williams Lake – the energy purchase agreement extension that became effective in April 2018 and provided lower pass-through of costs than the previous contract. The project also had lower dispatch than the comparable 2017 period. These factors resulted in a $3.7 million decrease in project revenue.

Consolidated project income increased by $25.7 million to $13.6 million in the three months ended June 30, 2018 from $(12.1) million in the three months ended June 30, 2017. The primary drivers of the increase are as follows:

Equity in earnings of unconsolidated affiliates – our equity in earnings of unconsolidated affiliates increased by $65.6 million for the three months ended June 30, 2018 primarily due to $57.7 million of impairments recorded at our Chambers and Selkirk projects in the comparable 2017 period, as well as $4.0 million and $2.6 million increases at our Frederickson and Orlando projects, respectively, due to higher maintenance expenses and longer maintenance outages incurred in the comparable 2017 period;

Fuel expense – fuel expense decreased $9.0 million from the comparable 2017 period primarily due to an $8.9 million decrease at the Naval Station, North Island and NTC projects, which ceased operations in February 2018; and

Depreciation and amortization expense – depreciation and amortization expense decreased by $8.5 million from the comparable 2017 period primarily due to decreases of $4.4 million and $3.7 million at our Kapuskasing and North Bay projects, respectively, which were fully depreciated as of December 31, 2017, a $1.6 million decrease at Williams Lake, which recorded a $29.1 million impairment in the fourth quarter of 2017, and a $3.4 million decrease at our San Diego projects due to accelerated depreciation since the third quarter of 2017. These decreases were partially offset by $4.4 million of increased amortization of the PPA intangible asset at our Nipigon project.

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

Project revenue – project revenue decreased $57.8 million as discussed above.

Project revenue decreased by $76.2 million to $146.2 million in the six months ended June 30, 2018 from $222.4 million in the six months ended June 30, 2017. The primary drivers of the decrease are as follows:

San Diego projects – the Naval Station, North Island and NTC projects ceased operations in February 2018, which resulted in a $29.7 million decrease in project revenue;

Enhanced dispatch contracts – the enhanced dispatch contracts with the IESO for Kapuskasing and North Bay expired in December 2017, which resulted in a $27.1 million decrease in project revenue;

Williams Lake – the energy purchase agreement extension that became effective in April 2018 and provided lower pass-through of costs than the previous contract. These factors resulted in a $2.8 million decrease in project revenue.

These decreases were partially offset by:

Morris project – $4.8 million increase in revenue at our Morris project due to higher capacity prices, higher merchant dispatch, and higher steam and ancillary services than the comparable 2017.

Consolidated project income increased by $28.6 million to $41.8 million in the six months ended June 30, 2018 from $13.2 million in the six months ended June 30, 2017. The primary drivers of the increase are as follows:

Equity in earnings of unconsolidated affiliates – our equity earnings of unconsolidated affiliates increased by $68.9 million for the six months ended June 30, 2018 primarily due to $57.7 million of impairments recorded at our Chambers and Selkirk projects in the comparable 2017 period, as well as $5.0 million and $3.8 million increases at our Frederickson and Orlando projects, respectively, due to higher maintenance expenses and longer maintenance outages incurred in the comparable 2017 period;

Fuel expense – fuel expense decreased $15.7 million from the comparable 2017 period primarily due to a $14.8 million decrease at the Naval Station, North Island and NTC projects, which ceased operations in February 2018;

Depreciation and amortization expense – depreciation and amortization expense decreased by $14.3 million from the comparable 2017 period primarily due to decreases of $8.8 million and $7.4 million at our Kapuskasing and North Bay projects, respectively, which were fully depreciated as of December 31, 2017. This decrease was partially offset by $9.0 million of increased amortization of the PPA intangible asset at our Nipigon project; and

Fuel swap and natural gas purchase agreements – the change in fair value of our derivative instruments increased $7.4 million from the comparable 2017 period.

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

Project revenue – project revenue decreased $76.2 million as discussed above.

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

We have four reportable segments: East U.S., West U.S., Canada and Un‑Allocated Corporate. The segment classified as Un‑allocated Corporate includes activities that support the executive and administrative offices, capital

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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.

Three months ended June 30, 2018 compared to the three months ended June 30, 2017

The following table provides our consolidated results of operations:


	Three months ended June 30,
	2018		2017		$ change		% change
Project revenue:
Energy sales	$	31.4	$	40.0	$	(8.6)	(21.5)	%
Energy capacity revenue		23.3		28.3		(5.0)	(17.7)	%
Other		11.5		55.7		(44.2)	(79.4)	%
		66.2		124.0		(57.8)	(46.6)	%
Project expenses:
Fuel		15.0		24.0		(9.0)	(37.5)	%
Operations and maintenance		27.2		23.3		3.9	16.7	%
Depreciation and amortization		21.0		29.5		(8.5)	(28.8)	%
		63.2		76.8		(13.6)	(17.7)	%
Project other income (loss):
Change in fair value of derivative instruments		(0.2)		(2.7)		2.5	(92.6)	%
Equity in earnings (loss) of unconsolidated affiliates		11.2		(54.4)		65.6	NM (1)
Interest, net		(0.4)		(2.2)		1.8	(81.8)	%
		10.6		(59.3)		69.9	(117.9)	%
Project income (loss)		13.6		(12.1)		25.7	NM
Administrative and other expenses:
Administration		6.2		5.7		0.5	8.8	%
Interest expense, net		11.1		18.4		(7.3)	(39.7)	%
Foreign exchange (gain) loss		(5.4)		5.9		(11.3)	NM
Other income, net		(0.2)		—		(0.2)	NM
		11.7		30.0		(18.3)	(61.0)	%
Income (loss) from operations before income taxes		1.9		(42.1)		44.0	NM
Income tax expense (benefit)		0.9		(22.3)		23.2	NM
Net income (loss)		1.0		(19.8)		20.8	NM
Net income attributable to preferred shares of a subsidiary company		1.6		2.1		(0.5)	(23.8)	%
Net loss attributable to Atlantic Power Corporation	$	(0.6)	$	(21.9)	$	21.3	NM

⁽¹⁾

NM is defined as “not meaningful” and includes changes greater than 200%.

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	Three months ended June 30, 2018
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	21.6	$	1.7	$	8.1	$	—	$	31.4
Energy capacity revenue		13.6		6.8		2.9		—		23.3
Other		3.8		(0.2)		7.7		0.2		11.5
		39.0		8.3		18.7		0.2		66.2
Project expenses:
Fuel		10.5		1.4		3.1		—		15.0
Operations and maintenance		9.5		11.1		6.6		—		27.2
Depreciation and amortization		9.1		3.9		8.0		—		21.0
		29.1		16.4		17.7		—		63.2
Project other income (expense):
Change in fair value of derivative instruments		(0.5)		—		0.2		0.1		(0.2)
Equity in earnings of unconsolidated affiliates		9.4		1.8		—		—		11.2
Interest expense, net		(0.4)		—		—		—		(0.4)
		8.5		1.8		0.2		0.1		10.6
Project income (loss)	$	18.4	$	(6.3)	$	1.2	$	0.3	$	13.6


	Three months ended June 30, 2017
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	24.4	$	7.8	$	7.8	$	—	$	40.0
Energy capacity revenue		12.4		13.3		2.6		—		28.3
Other		3.6		6.8		45.0		0.3		55.7
		40.4		27.9		55.4		0.3		124.0
Project expenses:
Fuel		10.5		10.5		3.0		—		24.0
Operations and maintenance		9.2		7.2		7.2		(0.3)		23.3
Depreciation and amortization		8.9		7.3		13.2		0.1		29.5
		28.6		25.0		23.4		(0.2)		76.8
Project other income (expense):
Change in fair value of derivative instruments		(0.7)		—		(0.9)		(1.1)		(2.7)
Equity in loss of unconsolidated affiliates		(52.2)		(2.2)		—		—		(54.4)
Interest expense, net		(2.2)		—		—		—		(2.2)
		(55.1)		(2.2)		(0.9)		(1.1)		(59.3)
Project (loss) income	$	(43.3)	$	0.7	$	31.1	$	(0.6)	$	(12.1)

East U.S.

Project income for the three months ended June 30, 2018 increased $61.7 million from the project loss in comparable 2017 period primarily due to:

increased project income of $48.1 million and $10.9 million at Chambers and Selkirk, respectively, primarily due to impairments of $47.1 million and $10.6 million recorded in the comparable 2017 period;

increased project income of $1.9 million at Orlando primarily due to higher availability and contractual capacity rates than the comparable 2017 period; and

increased project income of $2.1 million at Piedmont primarily due to $1.7 million of lower interest expense resulting from the repayment of the project-level debt, in full, in 2017.

These increases were partially offset by:

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decreased project income of $3.5 million at Curtis Palmer primarily due to lower water flows than the comparable 2017 period.

West U.S.

Project loss for the three months ended June 30, 2018 decreased $7.0 million from project income in the comparable 2017 period primarily due to:

decreased project income of $1.5 million, $1.4 million and $1.3 million at Naval Station, North Island and NTC, respectively, which ceased operations in February 2018; and

decreased project income of $7.2 million at Manchief primarily due to a $7.5 million increase in maintenance expense from a turbine overhaul.

These decreases were partially offset by:

increased project income of $4.0 million at Frederickson primarily due to higher maintenance expense recorded in the comparable 2017 period.

Canada

Project income for the three months ended June 30, 2018 decreased $29.9 million from the comparable 2017 period primarily due to:

decreased project income of $10.1 million at Kapuskasing primarily due to approximately $14.5 million of revenue recorded related to the OEFC settlement in the comparable period in 2017 and the expiration of the enhanced dispatch contract, partially offset by a $4.4 million decrease in depreciation expense;

decreased project income of $9.9 million at North Bay primarily due to approximately $13.8 million of revenue recorded related to the OEFC settlement in the comparable period in 2017 and the expiration of the enhanced dispatch contract, partially offset by a $3.7 million decrease in depreciation expense;

decreased project income of $8.1 million at Tunis primarily due to approximately $6.9 million of revenue recorded related to the OEFC settlement in the comparable period in 2017; and

decreased project income of $2.8 million at Nipigon primarily due to a $4.4 million increase in amortization expense from accelerated amortization of intangible PPA asset.

These decreases were partially offset by:

increased project income of $1.6 million at Mamquam primarily due to a maintenance outage that occurred in the 2017 comparable period.

Un‑allocated Corporate

Project income for the three months ended June 30, 2018 increased $0.9 million from project loss in the comparable 2017 period primarily due to a $1.1 million increase in fair value of interest swaps.

Administrative and other expenses (income)

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

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

Administration

Administration expense did not change materially from the 2017 comparable period.

Interest expense, net

Interest expense for the three months ended June 30, 2018 decreased $7.3 million from the comparable 2017 period primarily due to lower outstanding debt balances than the comparable 2017 period, as well as a lower interest rate on our senior secured credit facility.

Foreign exchange gains

Foreign exchange gain increased by $11.3 million to a $5.4 million gain in the three months ended June 30, 2018 from a $5.9 million loss in the comparable 2017 period, due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and convertible debentures). The closing U.S. dollar to Canadian dollar exchange rates were 1.32 and 1.30 at June 30, 2018 and 2017, respectively, an increase of 2.1% of the three months ended June 30, 2018 as compared to a decrease of 2.4% in the comparable 2017 period. The average U.S. dollar to Canadian dollar exchange rates were 1.30 and 1.34 for the three months ended June 30, 2018 and 2017, respectively.

Other income, net

Other income, net did not change materially from the comparable 2017 period.

Income tax expense

Income tax expense for the three months ended June 30, 2018 was $0.9 million. Expected income tax expense for the same period, based on the Canadian enacted statutory rate of 26%, was $0.5 million. The primary items impacting the tax rate for the three months ended June 30, 2018 were $0.3 million relating to foreign exchange and $0.2 million of other permanent differences. These items were partially offset by a net decrease to our valuation allowances of $0.1 million, consisting of $0.1 million decreases in Canada due to income and no changes in the United States for the period.

Income tax benefit for the three months ended June 30, 2017 was $22.3 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $11.0 million. The primary item increasing the tax rate for the three months ended June 30, 2017 was $0.2 million related to provision adjustments. This item was partially offset by $8.4 million relating to operating in higher tax rate jurisdictions, $2.6 million related to a net decrease to our valuation allowances in Canada due to income and $0.6 million relating to foreign exchange.

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Six months ended June 30, 2018 compared to the six months ended June 30, 2017

The following table provides our consolidated results of operations:


	Six months ended June 30,
	2018		2017		$ change		% change
Project revenue:
Energy sales	$	69.8	$	77.1	$	(7.3)	(9.5)	%
Energy capacity revenue		43.4		47.8		(4.4)	(9.2)	%
Other		33.0		97.5		(64.5)	(66.2)	%
		146.2		222.4		(76.2)	(34.3)	%
Project expenses:
Fuel		37.2		52.9		(15.7)	(29.7)	%
Operations and maintenance		48.5		43.6		4.9	11.2	%
Depreciation and amortization		44.7		59.0		(14.3)	(24.2)	%
		130.4		155.5		(25.1)	(16.1)	%
Project other expense:
Change in fair value of derivative instruments		3.5		(3.9)		7.4	NM
Equity in earnings (loss) of unconsolidated affiliates		23.5		(45.4)		68.9	NM
Interest expense, net		(1.0)		(4.4)		3.4	(77.3)	%
		26.0		(53.7)		79.7	(148.4)	%
Project income		41.8		13.2		28.6	NM
Administrative and other expenses (income):
Administration		12.2		12.1		0.1	0.8	%
Interest expense, net		26.1		35.7		(9.6)	(26.9)	%
Foreign exchange (gain) loss		(13.6)		8.3		(21.9)	NM
Other income, net		(2.2)		—		(2.2)	NM
		22.5		56.1		(33.6)	(59.9)	%
Income (loss) from operations before income taxes		19.3		(42.9)		62.2	NM
Income tax expense (benefit)		4.2		(22.6)		26.8	NM
Net income (loss)		15.1		(20.3)		35.4	NM
Net (loss) income attributable to preferred shares of a subsidiary company		(0.1)		4.3		(4.4)	NM
Net income (loss) attributable to Atlantic Power Corporation	$	15.2	$	(24.6)	$	39.8	NM


	Six months ended June 30, 2018
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	47.0	$	6.8	$	16.0	$	—	$	69.8
Energy capacity revenue		24.9		12.7		5.8		—		43.4
Other		8.7		2.4		21.4		0.5		33.0
		80.6		21.9		43.2		0.5		146.2
Project expenses:
Fuel		24.1		6.8		6.3		—		37.2
Operations and maintenance		17.8		16.7		13.7		0.3		48.5
Depreciation and amortization		18.2		10.3		16.1		0.1		44.7
		60.1		33.8		36.1		0.4		130.4
Project other income (expense):
Change in fair value of derivative instruments		(0.2)		—		1.4		2.3		3.5
Equity in earnings of unconsolidated affiliates		19.8		3.7		—		—		23.5
Interest expense, net		(1.0)		—		—		—		(1.0)
		18.6		3.7		1.4		2.3		26.0
Project income (loss)	$	39.1	$	(8.2)	$	8.5	$	2.4	$	41.8

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	Six months ended June 30, 2017
							Un-Allocated		Consolidated
	East U.S.		West U.S.		Canada		Corporate		Total
Project revenue:
Energy sales	$	46.2	$	16.2	$	14.7	$	—	$	77.1
Energy capacity revenue		22.5		20.0		5.3		—		47.8
Other		7.8		15.1		74.1		0.5		97.5
		76.5		51.3		94.1		0.5		222.4
Project expenses:
Fuel		23.1		22.1		7.7		—		52.9
Operations and maintenance		16.7		13.2		13.7		—		43.6
Depreciation and amortization		17.8		14.6		26.3		0.3		59.0
		57.6		49.9		47.7		0.3		155.5
Project other income (expense):
Change in fair value of derivative instruments		(1.3)		—		(4.1)		1.5		(3.9)
Equity in loss of unconsolidated affiliates		(44.0)		(1.4)		—		—		(45.4)
Interest expense, net		(4.4)		—		—		—		(4.4)
		(49.7)		(1.4)		(4.1)		1.5		(53.7)
Project (loss) income	$	(30.8)	$	—	$	42.3	$	1.7	$	13.2

East U.S.

Project income for the six months ended June 30, 2018 increased by $69.9 million to $39.1 million from a $(30.8) million project loss in the comparable 2017 period primarily due to:

increased project income of $48.5 million and $11.6 million at Chambers and Selkirk, respectively, primarily due to impairments of $47.1 million and $10.6 million, respectively, recorded in the comparable 2017 period;

increased project income of $4.5 million at Orlando primarily due to a $2.2 million increase in the change in fair value of derivatives and higher availability and contractual capacity rates than the comparable 2017 period;

increased project income of $4.1 million at Morris primarily due to higher energy and capacity energy revenues than the comparable 2017 period; and

increased project income of $3.5 million at Piedmont primarily due to $3.3 million of lower interest expense resulting from the repayment of the project-level debt, in full, in 2017.

These increases were partially offset by:

decreased project income of $3.1 million at Curtis Palmer primarily due to lower water flows than the comparable 2017 period.

West U.S.

Project loss for the six months ended June 30, 2018 increased $8.2 million from the comparable 2017 period primarily due to:

decreased project income of $2.3 million, $2.1 million and $1.7 million at North Island, Naval Station and NTC, respectively, which ceased operations in February 2018; and

decreased project income of $6.8 million at Manchief primarily due to a $7.5 million increase in maintenance expense from a turbine overhaul.

These decreases were partially offset by:

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increased project income of $5.0 million at Frederickson primarily due to lower planned maintenance expense than the comparable 2017 period.

Canada

Project income for the six months ended June 30, 2018 decreased $33.8 million from the comparable 2017 period primarily due to:

decreased project income of $13.5 million at North Bay primarily due to approximately $22.2 million of revenue recorded related to the OEFC settlement in the comparable period in 2017 and the expiration of the enhanced dispatch contract, partially offset by a $7.4 million decrease in depreciation expense;

decreased project income of $13.2 million at Kapuskasing primarily due to approximately $22.8 million of revenue recorded related to the OEFC settlement in the comparable period in 2017 and the expiration of the enhanced dispatch contract, partially offset by an $8.8 million decrease in depreciation expense; and

decreased project income of $10.7 million at Tunis primarily due to approximately $6.9 million of revenue recorded related to the OEFC settlement in the comparable 2017 period and a $4.0 million increase in maintenance expense in preparation of commencing operation in the fourth quarter of 2018.

These decreases were partially offset by:

increased project income of $2.4 million at Mamquam primarily due to maintenance outage in the comparable period in 2017; and

increased project income of $1.4 million at Williams Lake primarily due to a $3.2 million decrease in depreciation expense resulting from a $28.5 million long-lived asset impairment recorded in the fourth quarter of 2017, partially offset by a $1.3 million increase in maintenance expense.

Un‑allocated Corporate

Project income for the six months ended June 30, 2018 increased $0.7 million primarily due to a $0.8 million increase in change in fair value of interest swaps valuation.

Administrative and other expenses (income)

Administration

Administration expense did not change materially from the 2017 comparable period.

Interest expense, net

Interest expense decreased $9.6 million from the comparable 2017 period primarily due to lower outstanding debt balances than the comparable 2017 period, as well as a lower interest rate on our senior secured credit facility.

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Foreign exchange gains

Foreign exchange gain increased by $21.9 million to a $13.6 million gain in the six month months ended June 30, 2018 from an $8.3 million loss in the comparable 2017 period, due to the revaluation of instruments denominated in Canadian dollars (primarily our MTNs and convertible debentures). The closing U.S. dollar to Canadian dollar exchange rates were 1.32 and 1.30 at June 30, 2018 and 2017, respectively, an increase of 5.0% in the six months ended June 30, 2018 as compared to a decrease of 3.3% in the comparable 2017 period. The average U.S. dollar to Canadian dollar exchange rates were 1.28 and 1.33 for the six months ended June 30, 2018 and 2017, respectively.

Other income, net

Other income, net increased $2.2 million primarily due to a $2.3 million change in fair value of the conversion option derivative related to the Series E Debentures.

Income tax expense

Income tax benefit for the six months ended June 30, 2017 was $22.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $11.2 million. The primary item impacting the tax rate for the six months ended June 30, 2017 was $0.3 million relating to return to provision adjustments. This was partially offset by $8.7 million relating to operating in higher tax rate jurisdictions, $1.9 million related to a net decrease to our valuation allowances in Canada due to income, $1.0 million relating to foreign exchange and $0.1 million of other permanent differences.

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 six months ended June 30, 2018. 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


	Generation
	Three months ended June 30,
			% change
(in Net GWh)	2018	2017	2018 vs. 2017
Segment
East U.S.	603.9	609.8	(1.0)	%
West U.S.	98.9	272.3	(63.7)	%
Canada	277.1	246.8	12.3	%
Total	979.9	1,128.9	(13.2)	%

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Three months ended June 30, 2018 compared with three months ended June 30, 2017

Aggregate power generation for the three months ended June 30, 2018 decreased 13.2% from the comparable 2017 period primarily due to:

decreased generation in the West U.S. segment primarily due to a combined 198.1 net GWh decrease in generation at Naval Station, North Island and NTC, which ceased operations in February 2018, partially offset by a 26.1 GWh net increase in generation at Manchief due to higher dispatch than the comparable 2017 period; and

decreased generation in the East U.S. segment primarily due to a 32.5 net GWh decrease in generation at Curtis Palmer due to lower water flows than the comparable 2017 period, an 11.4 net GWh decrease in generation at Piedmont due to a maintenance outage and a 9.1 net GWh decrease in generation at Selkirk, which was sold in November 2017, partially offset by a net 33.0 GWh increase at Orlando due to a maintenance outage in the comparable 2017 period and a 12.1 net GWh increase at Kenilworth due to a maintenance outage in the comparable 2017 period.

These decreases were partially offset by:

increased generation in the Canada segment primarily due to a 27.3 net GWh increase at Mamquam due to a 2017 forced outage and higher water flows than the comparable 2017 period.


	Generation
	Six months ended June 30,
			% change
(in Net GWh)	2018	2017	2018 vs. 2017
Segment
East U.S.	1,260.1	1,199.4	5.1	%
West U.S.	342.2	623.6	(45.1)	%
Canada	498.2	458.5	8.7	%
Total	2,100.5	2,281.5	(7.9)	%

Six months ended June 30, 2018 compared with six months ended June 30, 2017

Aggregate power generation for the six months ended June 30, 2018 decreased 7.9% from the comparable 2017 period primarily due to:

decreased generation in the West U.S. segment primarily due to a combined 312.1 net GWh decrease in generation at Naval Station, North Island and NTC, which ceased operations in February 2018, and a 46.4 net GWh decrease in generation at Frederickson due to low demand, partially offset by an 81.6 GWh increase in generation at Manchief due to higher dispatch than the comparable 2017 period.

These decreases were partially offset by:

increased generation in the East U.S. segment primarily due to a 45.6 net GWh increase in generation at Orlando due to a maintenance outage performed in the comparable 2017 period and a 38.3 net GWh increase in generation at Morris due to higher dispatch than the comparable period in 2017, partially offset by a 35.0 net GWh decrease in generation at Curtis Palmer due to lower water flows than the comparable 2017 period; and

increased generation in the Canada segment primarily due to a 34.9 net GWh increase at Mamquam due to a 2017 maintenance outage and higher water flows than the comparable 2017 period.

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Availability


	Availability
	Three months ended June 30,
					% change
	2018		2017		2018 vs. 2017
Segment
East U.S.	95.3	%	86.7	%	9.9	%
West U.S.	85.2	%	72.0	%	18.3	%
Canada	96.4	%	87.0	%	10.8	%
Weighted average	93.4	%	83.6	%	11.7	%

Three months ended June 30, 2018 compared with three months ended June 30, 2017

Aggregate power availability for the three months ended June 30, 2018 increased 11.7% from the comparable 2017 period primarily due to:

increased availability in the West U.S. segment primarily due to maintenance outages at Frederickson in the comparable 2017 period, partially offset by decreased availability at Manchief due to a maintenance outage in the 2018 period;

increased availability in the Canada segment primarily due to a maintenance outage at Mamquam in the comparable 2017 period; and

increased availability in the East U.S. segment primarily due to maintenance outages at Kenilworth and Orlando in the comparable 2017 period.


	Availability
	Six months ended June 30,
					% change
	2018		2017		2018 vs. 2017
Segment
East U.S.	96.7	%	91.7	%	5.5	%
West U.S.	93.3	%	85.3	%	9.4	%
Canada	98.1	%	88.9	%	10.3	%
Weighted average	96.0	%	89.9	%	6.8	%

Six months ended June 30, 2018 compared with six months ended June 30, 2017

Aggregate power availability for the six months ended June 30, 2018 increased 6.8% from the comparable 2017 period primarily due to:

increased availability in the Canada segment primarily due to a maintenance outage at Mamquam in the comparable 2017 period;

increased availability in the East U.S. segment primarily due to maintenance outages at Kenilworth and Orlando in the comparable 2017 period and a shorter maintenance outage at Piedmont in 2018 than in the comparable 2017 period.

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 income (loss) to Project income and to Project Adjusted EBITDA is provided under “Project Adjusted EBITDA” below. Project Adjusted EBITDA for our equity investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below.

Project Adjusted EBITDA


	Three months ended						Six months ended
	June 30,				$ change		June 30,				$ change
	2018		2017		2018 vs 2017		2018		2017		2018 vs 2017
Net income (loss)	$	1.0	$	(19.8)	$	20.8	$	15.1	$	(20.3)	$	35.4
Income tax expense (benefit)		0.9		(22.3)		23.2		4.2		(22.6)		26.8
Income (loss) from operations before income taxes		1.9		(42.1)		44.0		19.3		(42.9)		62.2
Administration		6.2		5.7		0.5		12.2		12.1		0.1
Interest expense, net		11.1		18.4		(7.3)		26.1		35.7		(9.6)
Foreign exchange (gain) loss		(5.4)		5.9		(11.3)		(13.6)		8.3		(21.9)
Other income, net		(0.2)		—		(0.2)		(2.2)		—		(2.2)
Project income (loss)	$	13.6	$	(12.1)	$	25.7	$	41.8	$	13.2	$	28.6
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization		25.1		34.7		(9.6)		53.1		69.3		(16.2)
Interest expense, net		0.9		2.5		(1.6)		1.9		5.3		(3.4)
Change in the fair value of derivative instruments		0.2		2.6		(2.4)		(3.6)		3.8		(7.4)
Impairment		—		57.7		(57.7)		—		57.7		(57.7)
Project Adjusted EBITDA	$	39.8	$	85.4	$	(45.6)	$	93.2	$	149.3	$	(56.1)
Project Adjusted EBITDA by segment
East U.S.		31.2		29.1		2.1		64.4		56.2		8.2
West U.S.		(0.7)		10.6		(11.3)		5.4		19.8		(14.4)
Canada		9.0		45.2		(36.2)		23.2		72.8		(49.6)
Un-Allocated Corporate		0.3		0.5		(0.2)		0.2		0.5		(0.3)
Total	$	39.8	$	85.4	$	(45.6)	$	93.2	$	149.3	$	(56.1)

East U.S.

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


	Three months ended June 30,
					% change
	2018		2017		2018 vs. 2017
East U.S.
Project Adjusted EBITDA	$	31.2	$	29.1	7	%

Three months ended June 30, 2018 compared with three months ended June 30, 2017

Project Adjusted EBITDA for the three months ended June 30, 2018 increased $2.1 million from the comparable 2017 period primarily due to increased Project Adjusted EBITDA of:

$2.0 million at Orlando due to higher availability and contractual capacity rates than the comparable 2017 period;

$1.7 million at Morris due to $1.1 million of increased revenue from higher capacity rates than the comparable 2017 period; and

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$1.0 million at Chambers due to higher merchant dispatch and lower maintenance expense than the comparable 2017 period.

These increases were partially offset by decreased Project Adjusted EBITDA of:

$3.5 million at Curtis Palmer due to lower water flows than the comparable 2017 period.


	Six months ended June 30,
					% change
	2018		2017		2018 vs. 2017
East U.S.
Project Adjusted EBITDA	$	64.4	$	56.2	15	%

Six months ended June 30, 2018 compared with six months ended June 30, 2017

Project Adjusted EBITDA for the six months ended June 30, 2018 increased $8.2 million from the comparable 2017 period primarily due to increased Project Adjusted EBITDA of:

$5.4 million at Morris due to $4.8 million of increased revenue from higher capacity prices, higher merchant dispatch, and higher steam and ancillary services than the comparable 2017 period;

$2.4 million at Orlando due to higher availability and contractual capacity rates than the comparable 2017 period;

$1.4 million at Chambers due to higher merchant dispatch and lower maintenance expense than the comparable 2017 period; and

$1.0 million at Selkirk, which had a project loss in the comparable 2017 period and was sold in the fourth quarter of 2017.

These increases were partially offset by decreased Project Adjusted EBITDA of:

$3.2 million at Curtis Palmer due to lower water flows than the comparable 2017 period.

West U.S.

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


	Three months ended June 30,
					% change
	2018		2017		2018 vs 2017
West U.S.
Project Adjusted EBITDA	$	(0.7)	$	10.6	(107)	%

Three months ended June 30, 2018 compared with three months ended June 30, 2017

Project Adjusted EBITDA for the three months ended June 30, 2018 decreased $11.3 million from the comparable 2017 period primarily due to decreased Project Adjusted EBITDA of:

$3.1 million, $2.5 million and $2.1 million at Naval Station, North Island and NTC, respectively, which ceased operations in February 2018; and

$7.2 million at Manchief due to a $7.4 million increase in maintenance expense from a gas turbine overhaul.

These decreases were partially offset by increased Project Adjusted EBITDA of:

$3.0 million at Frederickson primarily due to higher maintenance expense recorded in the comparable 2017

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period.


	Six months ended June 30,
					% change
	2018		2017		2018 vs 2017
West U.S.
Project Adjusted EBITDA	$	5.4	$	19.8	(73)	%

Six months ended June 30, 2018 compared with six months ended June 30, 2017

Project Adjusted EBITDA for the six months ended June 30, 2018 decreased $14.4 million from the comparable 2017 period primarily due to decreased Project Adjusted EBITDA of:

$4.2 million, $3.6 million and $2.6 million at Naval Station, North Island and Naval Training Center, respectively, which ceased operations in February 2018; and

$6.8 million at Manchief due to a $7.4 million increase in maintenance expense from a turbine overhaul.

These decreases were partially offset by increased Project Adjusted EBITDA of:

$3.1 million at Frederickson primarily due to higher maintenance expense recorded in the comparable 2017 period.

Canada

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


	Three months ended June 30,
					% change
	2018		2017		2018 vs. 2017
Canada
Project Adjusted EBITDA	$	9.0	$	45.2	(80)	%

Three months ended June 30, 2018 compared with three months ended June 30, 2017

Project Adjusted EBITDA for the three months ended June 30, 2018 decreased $36.2 million from the comparable 2017 period primarily due to decreased Project Adjusted EBITDA of:

$14.5 million and $13.6 million at Kapuskasing and North Bay, respectively, due to expiration of the enhanced dispatch agreements in December 2017 and the OEFC settlement received in the comparable 2017 period;

$8.1 million at Tunis primarily due to approximately $6.9 million of revenue recorded related to the OEFC settlement in the comparable 2017 period and higher maintenance expense incurred in order to restart operations planned for the fourth quarter of 2018; and

$2.8 million at Williams Lake primarily due to lower gross margin under the short-term contract extension.

These decreases were partially offset by increased Project Adjusted EBITDA of:

$1.6 million at Mamquam primarily due to higher water flows and the timing of maintenance expense relative to the comparable 2017 period.

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	Six months ended June 30,
					% change
	2018		2017		2018 vs. 2017
Canada
Project Adjusted EBITDA	$	23.2	$	72.8	(68)	%

Six months ended June 30, 2018 compared with six months ended June 30, 2017

Project Adjusted EBITDA for the six months ended June 30, 2018 decreased $49.6 million from the comparable 2017 period primarily due to decreased Project Adjusted EBITDA of:

$22.0 million and $20.9 million at Kapuskasing and North Bay, respectively, due to the expiration of the enhanced dispatch agreements in December 2017 and and the OEFC settlement received in December 2017;

$10.7 million at Tunis due to approximately $6.9 million of revenue recorded related to the OEFC settlement in the comparable 2017 period and higher maintenance expense incurred in order to restart operations planned for the fourth quarter of 2018; and

$1.8 million at Williams Lake primarily due to lower gross margin under the short-term contract extension.

These decreases were partially offset by increased Project Adjusted EBITDA of:

$2.5 million at Mamquam primarily due to higher water flows and the timing of maintenance expense relative to the comparable 2017 period; and

$2.3 million at Nipigon primarily due to a contractual rate increase and lower fuel expense than the comparable 2017 period.

Un‑allocated Corporate

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


	Three months ended June 30,
					% change
	2018		2017		2018 vs. 2017
Un-allocated Corporate
Project Adjusted EBITDA	$	0.3	$	0.5	NM

Three months ended June 30, 2018 compared with three months ended June 30, 2017

Project Adjusted EBITDA for the three months ended June 30, 2018 did not change materially from the comparable 2017 period.


	Six months ended June 30,
					% change
	2018		2017		2018 vs. 2017
Un-allocated Corporate
Project Adjusted EBITDA	$	0.2	$	0.5	NM

Six months ended June 30, 2018 compared with six months ended June 30, 2017

Project Adjusted EBITDA for the six months ended June 30, 2018 did not change materially from the comparable 2017 period.

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Liquidity and Capital Resources


	June 30,		December 31,
	2018		2017
Cash and cash equivalents	$	80.8	$	78.7
Restricted cash		1.9		6.2
Total		82.7		84.9
Revolving credit facility availability		122.6		119.5
Total liquidity	$	205.3	$	204.4

Overview

Our primary sources of liquidity are distributions from our projects and availability under our Revolving Credit Facility. Our 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 June 30, 2019 to March 31, 2037. 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, 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 internal or external growth opportunities” in our Annual Report on Form 10‑K for the year ended December 31, 2017.

We expect to reinvest approximately $36.2 million in our portfolio, including equity method investments, in the form of project capital expenditures and maintenance expenses in 2018, of which $22.3 million has been incurred through June 30, 2018. Such investments are generally paid at the project level. See “Liquidity and Capital Resources—Capital and Maintenance Expenditures” in our Annual Report on Form 10‑K for the year ended December 31, 2017. On July 27, 2018, we used $12.1 million of cash on-hand to acquire the remaining 50% partnership interest in Koma and buy-out the the operation and maintenance contract from the prior owner. We do not expect any other material or unusual requirements for cash outflows in 2018 for capital expenditures or other required investments. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months.

Consolidated Cash Flow Discussion

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


	Six months ended
	June 30,
	2018		2017		Change
Net cash provided by operating activities	$	78.4	$	85.7	$	(7.3)
Net cash used in investing activities		(2.4)		(4.2)		1.8
Net cash used in financing activities		(78.2)		(61.9)		(16.3)

Operating Activities

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

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For the six months ended June 30, 2018, the net decrease in cash provided by operating activities of $7.3 million was primarily the result of the following:

Contract expirations – the expiration of the enhanced dispatch contracts at our North Bay and Kapuskasing projects on December 31, 2017, as well as operations ceasing at our San Diego projects in February 2018, had a $35.2 million impact on cash flows from operations;

OEFC settlement – we received approximately $24.7 million related to our settlement with the OEFC in the comparable 2017 period; and

Major maintenance – a planned major maintenance outage at our Manchief project had a $6.8 million impact on cash flows from operations. Additionally, costs incurred to prepare our Tunis project for commercial operations had a $4.4 million impact on cash flows from operations.

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

Working capital – changes in working capital resulted in a $34.7 million increase in cash flows from operating activities primarily due to a $17.7 million decrease in working capital at our Kapuskasing, North Bay and San Diego projects, which were not in operation at June 30, 2018.

Interest expense – our interest payments were $13.2 million lower as compared to the comparable 2017 period due to lower interest rates on our senior secured credit facility and the repayment of Piedmont’s project-level debt in 2017;

Distributions from unconsolidated affiliates – we received $10.1 million in higher distributions from our unconsolidated affiliates, primarily at our Frederickson ($3.6 million increase) and Orlando ($5.0 million increase) projects; and

Morris –higher capacity prices, higher merchant dispatch and higher steam and ancillary services than the comparable 2017 period had a $5.4 million impact on cash flows from operations at Morris in the six months ended June 30, 2018.

Investing Activities

For the six months ended June 30, 2018, the net decrease in cash used in investing activities of $1.8 million was primarily the result of the following:

Capitalized plant additions – capitalized plant additions were $2.9 million lower in the six months ended June 30, 2018 than the comparable 2017 period.

This increase was partially offset by the following increase to cash used in financing activities:

Investment in unconsolidated affiliate – we paid $1.1 million to acquire an additional 0.25% ownership of Koma.

Financing Activities

For the six months ended June 30, 2018, the net increase in cash used in financing activities of $16.3 million was primarily the result of the following:

Convertible debenture redemptions – we paid $88.0 million to redeem and cancel the Series C Debentures, in full, and the Series D Debentures, in part, with proceeds from the issuance of the Series E Debentures;

Corporate and project-level debt repayments – we made $1.9 million of higher principal payments than the comparable 2017 period;

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Preferred share repurchases – we paid $4.5 million in the six months ended June 30, 2018 to repurchase and cancel preferred shares;

Common share repurchases – we paid $9.2 million in the six months ended June 30, 2018 to repurchase and cancel common shares; and

Deferred financing costs – we incurred $4.8 million of deferred financing costs related to the issuance of the Series E Debentures.

These decreases were partially offset by the following decreases to cash flows used in financing activities:

Convertible debenture issuance – we received $92.2 million from the issuance of the Series E Debentures.

Corporate Debt

The following table summarizes the maturities of our corporate debt at June 30, 2018:


							Remaining
	Maturity	Interest					Principal
	Date	Rates					Repayments		2018		2019		2020		2021		2022		Thereafter
Senior secured term loan facility(1)	April 2023	3.87	%	-	5.42	%	$	490.0	$	40.0	$	65.0	$	105.0	$	80.0	$	75.0	$	125.0
Atlantic Power Income LP Note	June 2036	5.95	%					159.5		—		—		—		—		—		159.5
Convertible Debenture	December 2019	6.00	%					18.8		—		18.8		—		—		—		—
Convertible Debenture	January 2025	6.00	%					87.3		—		—		—		—		—		87.3
Total Corporate Debt							$	755.6	$	40.0	$	83.8	$	105.0	$	80.0	$	75.0	$	371.8

⁽¹⁾

The Credit Facility contains a mandatory amortization feature determined by using the greater of (i) 50% of the cash flow of APLP Holdings and its subsidiaries that remains after the application of funds, in accordance with a customary priority, to operations and maintenance expenses of APLP Holdings and its subsidiaries, debt service on the Credit Facilities and the 5.95% MTNs, 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 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.

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 June 30, 2018. Certain of the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project‑level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. At August 1, 2018, 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 June 30, 2018. The amounts listed below are in millions of U.S. dollars, except as otherwise stated.

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							Total
							Remaining
	Maturity	Range of					Principal
	Date	Interest Rates					Repayments		2018		2019		2020		2021		2022		Thereafter
Consolidated Projects:
Cadillac	August 2025	6.14	%	-	6.38	%	$	22.5	$	1.5	$	3.1	$	3.1	$	2.7	$	3.3	$	8.8
Total Consolidated Projects								22.5		1.5		3.1		3.1		2.7		3.3		8.8
Equity Method Projects:
Chambers(1)	December 2019 and 2023	4.50	%	-	5.00	%		42.9		—		5.2		7.8		8.8		10.1		11.0
Total Equity Method Projects								42.9		—		5.2		7.8		8.8		10.1		11.0
Total Project-Level Debt							$	65.4	$	1.5	$	8.3	$	10.9	$	11.5	$	13.4	$	19.8

⁽¹⁾

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

Uses of Liquidity

Our requirements for liquidity and capital resources, other than operating our projects, consist primarily of principal and interest on our outstanding convertible debentures, senior secured term loans, MTNs 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 $1.4 million in 2018 (of which $0.3 million was reinvested in the six months ended June 30, 2018) in our portfolio, including equity method investments, in the form of project capital expenditures, and incur $34.8 million of maintenance expenses (of which $22.0 million was incurred in the six months ended June 30, 2018). Such investments are generally paid at the project level. See “Liquidity and Capital Resources—Capital and Maintenance Expenditures” in our Annual Report on Form 10‑K for the year ended December 31, 2017. We do not expect any other material or unusual requirements for cash outflows for 2018 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 2018 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 June 30, 2018, we had no off‑balance sheet arrangements as defined in Item 303(a)(4) of Regulation S‑K.

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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, 2017.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d- 15(e) of the Exchange Act 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 six months ended June 30, 2018, 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.

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, 2017 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, 2017 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.

ITEM 2: UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEED

Share Repurchase Program

On December 29, 2017, we commenced an NCIB for each of our Series C and Series D Debentures, our common shares and for each series of the preferred shares of APPEL, our wholly-owned subsidiary. The NCIB expires on December 28, 2018 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 a total of 11,308,946 common shares based on 10% of our public float as of December 15, 2017 and we are limited to daily purchases of 11,789 common shares per day with certain exceptions including block purchases and purchases on other approved exchanges. On June 21, 2018, we amended the NCIB to increase the number of the Series 1 Preferred Shares that we may purchase to 475,000, representing approximately 10% of the 4,750,000 preferred shares public float as of December 15, 2017; increase the number of Series 2 Preferred Shares that we may purchase to 233,609, representing approximately 10% of the 2,338,094 preferred shares public float as of December 15, 2017; and increase the number of Series 3 Preferred Shares that we may purchase to 164,790, representing approximately 10% of the 1,661,906 preferred shares public float as of December 15, 2017. Daily repurchases are not affected by the amendment and each series will be limited to 1,000 preferred shares daily, other than block purchase exemptions.

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Through June 30, 2018, we repurchased and cancelled approximately 4.3 million shares at a cost of $9.2 million. We also repurchased and cancelled approximately 237,500 of our Series 1 Preferred Shares and 123,095 of our Series 3 Preferred Shares, for a total payment of Cdn$5.8 million in the six months ended June 30, 2018.

The following table provides purchases of equity securities by the Issuer and Affiliated Purchases for the period of April 1, 2018 through June 30, 2018:


					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
Purchase Period	Shares Purchased		Per Share		Purchase Plan		the Plan
4/1/2018 - 4/30/2018		498,605		$ 2.14		498,605		$ 23,049,390
5/1/2018 - 5/31/2018		20,500		$ 2.15		20,500		$ 22,988,095
6/1/2018 - 6/30/2018		792,948		$ 2.13		792,948		$ 20,617,180
Total		1,312,053				1,312,053

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ITEM 6. EXHIBITS

EXHIBIT INDEX


Exhibit No.		Description
10.1*		Third Amendment dated April 19, 2018 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: August 2, 2018	Atlantic Power Corporation


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