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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

ý |  | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2013
OR
o |  | 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.)
One Federal Street, 30th Floor Boston, MA (Address of principal executive offices) |  | 02110 (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 ý No o

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 ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý |  | Accelerated filer o |  | Non-accelerated filer o (Do not check if a smaller reporting company) |  | Smaller reporting company o

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

The number of shares outstanding of the registrant's Common Stock as of November 7, 2013 was 120,044,879.

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ATLANTIC POWER CORPORATION
FORM 10-Q
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013
Index

|  | General: |  | 3
|  | PART I—FINANCIAL INFORMATION |  | 4
ITEM 1. |  | CONSOLIDATED FINANCIAL STATEMENTS AND NOTES |  | 4
|  | Consolidated Balance Sheets as of September 30, 2013 (unaudited) and December 31, 2012 |  | 4
|  | Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and September 30, 2012 (unaudited) |  | 5
|  | Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2013 and September 30, 2012 (unaudited) |  | 6
|  | Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and September 30, 2012 (unaudited) |  | 7
|  | Notes to Consolidated Financial Statements (unaudited) |  | 8
ITEM 2. |  | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  | 50
ITEM 3. |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |  | 83
ITEM 4. |  | CONTROLS AND PROCEDURES |  | 86
|  | PART II—OTHER INFORMATION |  | 88
ITEM 1. |  | LEGAL PROCEEDINGS |  | 88
ITEM 1A. |  | RISK FACTORS |  | 90
ITEM 6. |  | EXHIBITS |  | 90

Table of Contents

GENERAL

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

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

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PART I—FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)

|  | September 30, 2013 |  | December 31, 2012 |
--- | --- | --- | --- | --- | ---
|  | (unaudited) |  |  |
Assets |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 170.7 |  | $ | 60.2 |
Restricted cash |  |  | 119.8 |  |  | 28.6 |
Accounts receivable |  |  | 63.3 |  |  | 58.5 |
Current portion of derivative instruments asset (Notes 6 and 7) |  |  | 0.3 |  |  | 9.5 |
Inventory |  |  | 18.3 |  |  | 16.9 |
Prepayments and other current assets |  |  | 13.3 |  |  | 13.4 |
Security deposits |  |  | — |  |  | 19.0 |
Assets held for sale (Note 11) |  |  | 0.5 |  |  | 351.4 |
Refundable income taxes |  |  | 1.9 |  |  | 4.2 |
Total current assets |  |  | 388.1 |  |  | 561.7 |
Property, plant, and equipment, net of accumulated depreciation of $152.1 million and $79.2 million at September 30, 2013 and December 31, 2012, respectively |  |  | 1,873.9 |  |  | 2,055.5 |
Equity investments in unconsolidated affiliates |  |  | 404.5 |  |  | 428.7 |
Other intangible assets, net of accumulated amortization of $123.4 million and $76.9 million at September 30, 2013 and December 31, 2012, respectively |  |  | 471.1 |  |  | 524.9 |
Goodwill (Note 4) |  |  | 296.3 |  |  | 334.7 |
Derivative instruments asset (Notes 6 and 7) |  |  | 9.5 |  |  | 11.1 |
Other assets |  |  | 53.3 |  |  | 86.1 |
Total assets |  | $ | 3,496.7 |  | $ | 4,002.7 |
Liabilities |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |
Accounts payable |  | $ | 11.1 |  | $ | 17.8 |
Accrued interest |  |  | 30.0 |  |  | 19.0 |
Other accrued liabilities |  |  | 49.0 |  |  | 73.7 |
Senior credit facility (Note 5) |  |  | — |  |  | 67.0 |
Current portion of long-term debt (Note 5) |  |  | 206.7 |  |  | 121.2 |
Current portion of derivative instruments liability (Notes 6 and 7) |  |  | 32.9 |  |  | 33.0 |
Dividends payable |  |  | 3.9 |  |  | 11.5 |
Liabilities held for sale (Note 11) |  |  | 0.1 |  |  | 189.0 |
Other current liabilities |  |  | 6.0 |  |  | 3.3 |
Total current liabilities |  |  | 339.7 |  |  | 535.5 |
Long-term debt (Note 5) |  |  | 1,274.1 |  |  | 1,459.1 |
Convertible debentures |  |  | 414.1 |  |  | 424.2 |
Derivative instruments liability (Notes 6 and 7) |  |  | 87.0 |  |  | 118.1 |
Deferred income taxes |  |  | 151.2 |  |  | 164.0 |
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $7.2 million and $4.4 million at September 30, 2013 and December 31, 2012, respectively |  |  | 40.3 |  |  | 44.0 |
Other non-current liabilities |  |  | 69.3 |  |  | 71.4 |
Commitments and contingencies (Note 14) |  |  | — |  |  | — |
Total liabilities |  |  | 2,375.7 |  |  | 2,816.3 |
Equity |  |  |  |  |  |  |
Common shares, no par value, unlimited authorized shares; 120,044,879 and 119,446,865 issued and outstanding at September 30, 2013 and December 31, 2012, respectively (Note 12) |  |  | 1,285.7 |  |  | 1,285.5 |
Preferred shares issued by a subsidiary company (Note 12) |  |  | 221.3 |  |  | 221.3 |
Accumulated other comprehensive income (loss) |  |  | (8.7 | ) |  | 9.4 |
Retained deficit |  |  | (649.6 | ) |  | (565.2 | )
Total Atlantic Power Corporation shareholders' equity |  |  | 848.7 |  |  | 951.0 |
Noncontrolling interest (Note 12) |  |  | 272.3 |  |  | 235.4 |
Total equity |  |  | 1,121.0 |  |  | 1,186.4 |
Total liabilities and equity |  | $ | 3,496.7 |  | $ | 4,002.7 |

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(Unaudited)

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 73.4 |  | $ | 49.6 |  | $ | 228.6 |  | $ | 159.0 |
Energy capacity revenue |  |  | 51.1 |  |  | 42.8 |  |  | 132.2 |  |  | 117.3 |
Other |  |  | 17.3 |  |  | 13.9 |  |  | 60.2 |  |  | 50.1 |
|  |  | 141.8 |  |  | 106.3 |  |  | 421.0 |  |  | 326.4 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 47.2 |  |  | 40.1 |  |  | 148.8 |  |  | 123.6 |
Operations and maintenance |  |  | 38.0 |  |  | 26.5 |  |  | 112.3 |  |  | 88.0 |
Development |  |  | 1.4 |  |  | — |  |  | 4.9 |  |  | — |
Depreciation and amortization |  |  | 42.2 |  |  | 30.6 |  |  | 125.7 |  |  | 87.3 |
|  |  | 128.8 |  |  | 97.2 |  |  | 391.7 |  |  | 298.9 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments (Notes 6 and 7) |  |  | (3.5 | ) |  | 10.7 |  |  | 33.4 |  |  | (51.3 | )
Equity in earnings of unconsolidated affiliates (Note 3) |  |  | 39.1 |  |  | 4.0 |  |  | 55.0 |  |  | 12.4 |
Interest expense, net |  |  | (9.0 | ) |  | (4.1 | ) |  | (25.7 | ) |  | (12.3 | )
Impairment of goodwill (Note 4) |  |  | (34.9 | ) |  | — |  |  | (34.9 | ) |  | — |
Other, net |  |  | 0.1 |  |  | — |  |  | 0.2 |  |  | — |
|  |  | (8.2 | ) |  | 10.6 |  |  | 28.0 |  |  | (51.2 | )
Project income (loss) |  |  | 4.8 |  |  | 19.7 |  |  | 57.3 |  |  | (23.7 | )
Administrative and other expenses (income): |  |  |  |  |  |  |  |  |  |  |  |  |
Administration |  |  | 8.4 |  |  | 6.3 |  |  | 28.5 |  |  | 22.0 |
Interest, net |  |  | 27.5 |  |  | 25.8 |  |  | 78.7 |  |  | 69.3 |
Foreign exchange loss (gain) (Note 7) |  |  | 9.1 |  |  | 7.7 |  |  | (12.9 | ) |  | 4.4 |
Other expense (income), net |  |  | — |  |  | 0.3 |  |  | (9.5 | ) |  | (5.7 | )
|  |  | 45.0 |  |  | 40.1 |  |  | 84.8 |  |  | 90.0 |
Loss from continuing operations before income taxes |  |  | (40.2 | ) |  | (20.4 | ) |  | (27.5 | ) |  | (113.7 | )
Income tax expense (benefit) (Note 8) |  |  | — |  |  | 3.1 |  |  | (1.9 | ) |  | (19.1 | )
Loss from continuing operations |  |  | (40.2 | ) |  | (23.5 | ) |  | (25.6 | ) |  | (94.6 | )
Net income (loss) from discontinued operations, net of tax (Note 11) |  |  | (0.4 | ) |  | 19.0 |  |  | (6.1 | ) |  | 48.8 |
Net loss |  |  | (40.6 | ) |  | (4.5 | ) |  | (31.7 | ) |  | (45.8 | )
Net loss attributable to noncontrolling interests |  |  | (2.5 | ) |  | (0.4 | ) |  | (3.3 | ) |  | (0.7 | )
Net income attributable to preferred shares dividends of a subsidiary company |  |  | 3.2 |  |  | 3.4 |  |  | 9.5 |  |  | 9.8 |
Net loss attributable to Atlantic Power Corporation |  | $ | (41.3 | ) | $ | (7.5 | ) | $ | (37.9 | ) | $ | (54.9 | )
Basic earnings (loss) per share: (Note 10) |  |  |  |  |  |  |  |  |  |  |  |  |
Loss from continuing operations attributable to Atlantic Power Corporation |  | $ | (0.34 | ) | $ | (0.22 | ) | $ | (0.27 | ) | $ | (0.90 | )
Income (loss) from discontinued operations, net of tax |  |  | (0.00 | ) |  | 0.16 |  |  | (0.05 | ) |  | 0.42 |
Net loss attributable to Atlantic Power Corporation |  | $ | (0.34 | ) | $ | (0.06 | ) | $ | (0.32 | ) | $ | (0.48 | )
Diluted earnings (loss) per share: (Note 10) |  |  |  |  |  |  |  |  |  |  |  |  |
Loss from continuing operations attributable to Atlantic Power Corporation |  | $ | (0.34 | ) | $ | (0.22 | ) | $ | (0.27 | ) | $ | (0.90 | )
Income (loss) from discontinued operations, net of tax |  |  | (0.00 | ) |  | 0.16 |  |  | (0.05 | ) |  | 0.42 |
Net loss attributable to Atlantic Power Corporation |  | $ | (0.34 | ) | $ | (0.06 | ) | $ | (0.32 | ) | $ | (0.48 | )
Weighted average number of common shares outstanding: (Note 10) |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 120.0 |  |  | 119.0 |  |  | 119.8 |  |  | 115.4 |
Diluted |  |  | 120.0 |  |  | 119.0 |  |  | 119.8 |  |  | 115.4 |

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 September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |
Net loss |  | $ | (40.6 | ) | $ | (4.5 | )
Other comprehensive income (loss), net of tax: |  |  |  |  |  |  |
Unrealized loss on hedging activities |  | $ | (0.1 | ) | $ | (0.3 | )
Net amount reclassified to earnings |  |  | 0.2 |  |  | 0.1 |
Net unrealized gain (loss) on derivatives |  |  | 0.1 |  |  | (0.2 | )
Foreign currency translation adjustments |  |  | 10.7 |  |  | 19.3 |
Other comprehensive income, net of tax |  |  | 10.8 |  |  | 19.1 |
Comprehensive income (loss) |  |  | (29.8 | ) |  | 14.6 |
Less: Comprehensive income attributable to noncontrolling interest |  |  | 0.7 |  |  | 3.0 |
Comprehensive income (loss) attributable to Atlantic Power Corporation |  | $ | (30.5 | ) | $ | 11.6 |

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |
Net loss |  | $ | (31.7 | ) | $ | (45.8 | )
Other comprehensive income (loss), net of tax: |  |  |  |  |  |  |
Unrealized gain (loss) on hedging activities |  | $ | 0.5 |  | $ | (0.8 | )
Net amount reclassified to earnings |  |  | 0.6 |  |  | 0.5 |
Net unrealized gain (loss) on derivatives |  |  | 1.1 |  |  | (0.3 | )
Foreign currency translation adjustments |  |  | (19.3 | ) |  | 22.6 |
Other comprehensive income (loss), net of tax |  |  | (18.2 | ) |  | 22.3 |
Comprehensive loss |  |  | (49.9 | ) |  | (23.5 | )
Less: Comprehensive income attributable to noncontrolling interest |  |  | 6.2 |  |  | 9.1 |
Comprehensive loss attributable to Atlantic Power Corporation |  | $ | (56.1 | ) | $ | (32.6 | )

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions of U.S. dollars)

(Unaudited)

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |
Cash flows from operating activities: |  |  |  |  |  |  |
Net loss |  | $ | (31.7 | ) | $ | (45.8 | )
Adjustments to reconcile to net cash provided by operating activities: |  |  |  |  |  |  |
Depreciation and amortization |  |  | 135.0 |  |  | 117.5 |
Loss of discontinued operations |  |  | 32.8 |  |  | — |
(Gain) loss on sale of assets & other charges |  |  | (4.6 | ) |  | 0.8 |
Long-term incentive plan expense |  |  | 1.7 |  |  | 2.3 |
Impairment charges |  |  | 39.8 |  |  | 3.0 |
Gain on sale of equity investments |  |  | (30.4 | ) |  | (0.6 | )
Equity in earnings from unconsolidated affiliates |  |  | (24.6 | ) |  | (14.8 | )
Distributions from unconsolidated affiliates |  |  | 28.5 |  |  | 26.8 |
Unrealized foreign exchange loss |  |  | 1.5 |  |  | 21.7 |
Change in fair value of derivative instruments |  |  | (44.1 | ) |  | 41.0 |
Change in deferred income taxes |  |  | (11.9 | ) |  | (24.4 | )
Change in other operating balances |  |  |  |  |  |  |
Accounts receivable |  |  | 4.5 |  |  | (2.9 | )
Inventory |  |  | (1.5 | ) |  | (5.5 | )
Prepayments, refundable income taxes and other assets |  |  | 54.2 |  |  | (13.2 | )
Accounts payable |  |  | (11.9 | ) |  | 14.9 |
Accruals and other liabilities |  |  | 6.0 |  |  | 3.3 |
Cash provided by operating activities |  |  | 143.3 |  |  | 124.1 |
Cash flows provided by (used in) investing activities: |  |  |  |  |  |  |
Change in restricted cash |  |  | (99.1 | ) |  | (105.5 | )
Proceeds from sale of assets and equity investments, net |  |  | 183.0 |  |  | 27.9 |
Cash paid for equity investment |  |  | — |  |  | (0.3 | )
Proceeds from treasury grant |  |  | 103.2 |  |  | — |
Biomass development costs |  |  | (0.1 | ) |  | (0.4 | )
Construction in progress |  |  | (32.2 | ) |  | (336.0 | )
Purchase of property, plant and equipment |  |  | (7.2 | ) |  | (1.2 | )
Cash provided by (used in) investing activities |  |  | 147.6 |  |  | (415.5 | )
Cash flows (used in) provided by financing activities: |  |  |  |  |  |  |
Proceeds from issuance of convertible debentures |  |  | — |  |  | 130.0 |
Proceeds from issuance of equity, net of offering costs |  |  | — |  |  | 67.7 |
Proceeds from project-level debt |  |  | 20.8 |  |  | 261.3 |
Repayment of project-level debt |  |  | (115.4 | ) |  | (12.1 | )
Offering costs related to tax equity |  |  | (1.0 | ) |  | — |
Payments for revolving credit facility borrowings |  |  | (67.0 | ) |  | (60.8 | )
Proceeds from revolving credit facility borrowings |  |  | — |  |  | 22.8 |
Equity contribution from noncontrolling interest |  |  | 44.6 |  |  | — |
Deferred financing costs |  |  | (0.5 | ) |  | (25.3 | )
Dividends paid to common shareholders |  |  | (54.2 | ) |  | (108.2 | )
Dividends paid to noncontrolling interests |  |  | (13.9 | ) |  | — |
Cash (used in) provided by financing activities |  |  | (186.6 | ) |  | 275.4 |
Net increase (decrease) in cash and cash equivalents |  |  | 104.3 |  |  | (16.0 | )
Less cash at discontinued operations |  |  | (0.3 | ) |  | (1.8 | )
Cash and cash equivalents at beginning of period at discontinued operations |  |  | 6.5 |  |  | — |
Cash and cash equivalents at beginning of period |  |  | 60.2 |  |  | 60.7 |
Cash and cash equivalents at end of period |  | $ | 170.7 |  | $ | 42.9 |
Supplemental cash flow information |  |  |  |  |  |  |
Interest paid |  | $ | 87.0 |  | $ | 77.7 |
Income taxes paid, net |  | $ | 4.6 |  | $ | 3.1 |
Accruals for construction in progress |  | $ | 8.3 |  | $ | 40.1 |

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of presentation and summary of significant accounting policies

General

Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of September 30, 2013, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 3,018 megawatts ("MW") in which our aggregate ownership interest is approximately 2,098 MW. These totals exclude our 40% interest in the Delta-Person generating station ("Delta-Person") for which we entered into an agreement to sell in December 2012. Our current portfolio consists of interests in twenty-nine operational power generation projects across eleven states in the United States and two provinces in Canada. We also own Ridgeline Energy Holdings, Inc. ("Ridgeline"), a wind and solar developer in Seattle, and we own a majority interest in Rollcast Energy Inc. ("Rollcast"), a biomass power plant developer in North Carolina for which we have initiated a plan to sell our interest. Twenty-three of our projects are wholly owned subsidiaries.

Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange under the symbol "ATP" and on the New York Stock Exchange under the symbol "AT." Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 Canada and our headquarters is located at One Federal Street, 30th Floor, Boston, Massachusetts 02110, USA. Our telephone number in Boston 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.

The interim consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2012. Interim results are not necessarily indicative of results for the full year.

In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of September 30, 2013, the results of operations and comprehensive income (loss) for the three and nine months ended September 30, 2013 and 2012, and our cash flows for the nine months ended September 30, 2013 and 2012. 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 (Continued)

(Unaudited)

1. Basis of presentation and summary of significant accounting policies (Continued)

Use of estimates

The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, 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 valuation of shares associated with our Long-Term Incentive Plan ("LTIP") and the fair value of financial instruments and derivatives. 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, 2012. 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 July 2012, the Financial Accounting Standards Board ("FASB") issued changes to the testing of indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of an indefinite-lived intangible asset is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test. These changes became effective for us for any indefinite-lived intangible asset impairment test performed on January 1, 2013 or later. The adoption of these changes did not impact the consolidated financial statements.

On January 1, 2012, we adopted changes issued by the FASB to conform existing guidance regarding fair value measurement and disclosure between U.S. generally accepted accounting principles ("GAAP") and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's

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(Unaudited)

1. Basis of presentation and summary of significant accounting policies (Continued)

shareholders' equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. The adoption of these changes had no impact on the consolidated financial statements.

In December 2011, the FASB issued changes to the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The enhanced disclosures will enable users of an entity's financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity's financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. These changes became effective for us on January 1, 2013. Other than the additional disclosure requirements, the adoption of these changes did not impact the consolidated financial statements.

On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income. These changes require an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not required to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive income. Other than the additional disclosure requirements (see below), the adoption of these changes had no impact on the consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

1. Basis of presentation and summary of significant accounting policies (Continued)

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

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |
Foreign currency translation |  |  |  |  |  |  |
Balance at beginning of period |  | $ | (17.4 | ) | $ | (0.1 | )
Other comprehensive loss: |  |  |  |  |  |  |
Foreign currency translation adjustments(1) |  | $ | 10.7 |  |  | 19.3 |
Balance at end of period |  | $ | (6.7 | ) | $ | 19.2 |
Cash flow hedges |  |  |  |  |  |  |
Balance at beginning of period |  | $ | (0.4 | ) | $ | (1.5 | )
Other comprehensive income (loss): |  |  |  |  |  |  |
Net change from periodic revaluations |  |  | (0.2 | ) |  | (0.5 | )
Tax benefit |  |  | 0.1 |  |  | 0.2 |
Total Other comprehensive loss before reclassifications, net of tax |  |  | (0.1 | ) |  | (0.3 | )
Net amount reclassified to earnings: |  |  |  |  |  |  |
Interest rate swaps(2) |  |  | 0.3 |  |  | 0.4 |
Fuel commodity swaps(3) |  |  | — |  |  | (0.3 | )
Sub-total |  |  | 0.3 |  |  | 0.1 |
Tax expense(4) |  |  | (0.1 | ) |  | — |
Total amount reclassified from Accumulated other comprehensive loss, net of tax(5) |  |  | 0.2 |  |  | 0.1 |
Total Other comprehensive income (loss) |  |  | 0.1 |  |  | (0.2 | )
Balance at end of period |  |  | (0.3 | ) |  | (1.7 | )

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(Unaudited)

1. Basis of presentation and summary of significant accounting policies (Continued)

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |
Foreign currency translation |  |  |  |  |  |  |
Balance at beginning of period |  | $ | 12.7 |  | $ | (3.4 | )
Other comprehensive loss: |  |  |  |  |  |  |
Foreign currency translation adjustments(1) |  |  | (19.3 | ) |  | 22.6 |
Balance at end of period |  | $ | (6.6 | ) | $ | 19.2 |
Cash flow hedges |  |  |  |  |  |  |
Balance at beginning of period |  | $ | (1.4 | ) | $ | (1.4 | )
Other comprehensive loss: |  |  |  |  |  |  |
Net change from periodic revaluations |  |  | 0.9 |  |  | (1.4 | )
Tax (expense) benefit |  |  | (0.4 | ) |  | 0.6 |
Total Other comprehensive income (loss) before reclassifications, net of tax |  |  | 0.5 |  |  | (0.8 | )
Net amount reclassified to earnings: |  |  |  |  |  |  |
Interest rate swaps(2) |  |  | 1.2 |  |  | 1.2 |
Fuel commodity swaps(3) |  |  | (0.2 | ) |  | (0.4 | )
Sub-total |  |  | 1.0 |  |  | 0.8 |
Tax expense(4) |  |  | (0.4 | ) |  | (0.3 | )
Total amount reclassified from Accumulated other comprehensive loss, net of tax(5) |  |  | 0.6 |  |  | 0.5 |
Total Other comprehensive income (loss) |  |  | 1.1 |  |  | (0.3 | )
Balance at end of period |  |  | (0.3 | ) |  | (1.7 | )

(1)
  In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings.
(2)
  This amount was included in Interest, net on the accompanying Statement of Consolidated Operations.
(3)
  These amounts were included in Fuel on the accompanying Statement of Consolidated Operations.
(4)
  These amounts were included in Income tax expense (benefit) on the accompanying Statement of Consolidated Operations.
(5)
  A positive amount indicates a corresponding charge to earnings and a negative amount indicates a corresponding benefit to earnings. These amounts were reflected on the accompanying Statement of Consolidated Operations in the line items indicated in footnotes 1 through 4.

Issued

In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

1. Basis of presentation and summary of significant accounting policies (Continued)

deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. These changes become effective for us on January 1, 2014. Management has determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co- obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes become effective for us on January 1, 2014. We have determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

In March 2013, the FASB issued changes to a parent entity's accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive income into net income in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes become effective for us on January 1, 2014. We have determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

2. Acquisitions and divestments

2012 Acquisitions

(a)
  Canadian Hills

On January 31, 2012, Atlantic Oklahoma Wind, LLC ("Atlantic OW"), a Delaware limited liability company and our wholly owned subsidiary, entered into a purchase and sale agreement with Apex Wind Energy Holdings, LLC, a Delaware limited liability company ("Apex"), pursuant to which Atlantic OW acquired a 51% interest in Canadian Hills Wind, LLC, an Oklahoma limited liability company ("Canadian Hills") for a nominal sum. Canadian Hills is the owner of a 300 MW wind energy project in the state of Oklahoma.

On March 30, 2012, we completed the purchase of an additional 48% interest in Canadian Hills for a nominal amount, bringing our total interest in the project to 99%. Apex retained a 1% interest in the project. We also closed a $310 million non-recourse, project-level construction financing facility for the project, which included a $290 million construction loan and a $20 million 5-year letter of credit

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(Unaudited)

2. Acquisitions and divestments (Continued)

facility. In July 2012, we funded approximately $190 million of our equity contribution (net of financing costs). In December 2012, the project received tax equity investments in aggregate of $225 million from a consortium of four institutional tax equity investors along with an approximately $44 million tax equity investment of our own. The project's outstanding construction loan was repaid by the proceeds from these tax equity investments, decreasing the project's short-term debt by $265 million as of December 31, 2012. Canadian Hills has no debt at September 30, 2013. On May 2, 2013, we syndicated our $44 million tax equity investment in Canadian Hills to an institutional investor and received net cash proceeds of $42.1 million. The syndication of our interest completes the sale of 100% of Canadian Hills' $269 million of tax equity interests. The cash proceeds will be held for general corporate purposes.

We own 99% of the project and consolidate it in our consolidated financial statements. Income attributable to the tax equity investors is classified as noncontrolling interests and is allocated utilizing the hypothetical liquidation book value method ("HLBV").

2013 Divestments

(a)
  Gregory

On April 2, 2013, we and the other owners of Gregory, entered into a purchase and sale agreement with an affiliate of NRG Energy, Inc. to sell the project for approximately $274.2 million, including working capital adjustments. The sale of Gregory closed on August 7, 2013 resulting in a gain on sale of $30.4 million that was recorded in equity in earnings of unconsolidated affiliates in the consolidated statements of operations for the three and nine months ended September 30, 2013. We received net cash proceeds for our ownership interest of approximately $34.6 million in the aggregate, after repayment of project-level debt and transaction expenses. Approximately $5 million of these proceeds will be held in escrow for up to one year after the closing date. We intend to use the net proceeds from the sale for general corporate purposes.

(b)
  Path 15

On March 11, 2013, we entered into a purchase and sale agreement with Duke-American Transmission Company, a joint venture between Duke Energy Corporation and American Transmission Co., to sell our interests in the Path 15 transmission line ("Path 15"). The sale closed on April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of approximately $52.0 million, plus a management agreement termination fee of $4.0 million, for a total sale price of approximately $56.0 million. The cash proceeds will be used for general corporate purposes. All project level debt issued by Path 15, totaling $137.2 million, transferred with the sale. Path 15 was accounted for as an asset held for sale in the consolidated balance sheet at December 31, 2012 and as a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012. See Note 11, Assets held for sale and discontinued operations, for further information.

(c)
  Auburndale, Lake and Pasco

On January 30, 2013, we entered into a purchase and sale agreement for the sale of our Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco CoGen, Ltd.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

2. Acquisitions and divestments (Continued)

("Pasco") projects (collectively, the "Florida Projects") for approximately $140 million, including working capital adjustments. The sale closed on April 12, 2013 and we received net cash proceeds of approximately $117 million in the aggregate, after repayment of project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale. This includes approximately $92 million received at closing and cash distributions from the Florida Projects of approximately $25 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully repay our senior credit facility, which had an outstanding balance of approximately $64.1 million on the closing date. The remaining cash proceeds will be used for general corporate purposes. The Florida Projects were accounted for as assets held for sale in the consolidated balance sheets at December 31, 2012 and are a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012. See Note 11, Assets held for sale and discontinued operations, for further information.

2012 Divestments

(a)
  Badger Creek

On August 2, 2012, we entered into a purchase and sale agreement for the sale of our 50% ownership interest in the Badger Creek project. On September 4, 2012, the transaction closed and we received gross proceeds of $3.7 million. As a result of the pending sale, we recorded an impairment charge in the second quarter of 2012 of $3.0 million in equity in earnings from unconsolidated affiliates in the consolidated statements of operations.

(b)
  Primary Energy Recycling Corporation

On February 16, 2012, we entered into an agreement with Primary Energy Recycling Corporation ("Primary Energy" or "PERC"), whereby PERC agreed to purchase our 7,462,830.33 common membership interests in Primary Energy Recycling Holdings, LLC ("PERH") (14.3% of PERH total interests) for approximately $24.2 million, plus a management agreement termination fee of approximately $6.0 million, for a total sale price of $30.2 million. The transaction closed in May 2012 and we recorded a $0.6 million gain on sale of our equity investment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

3. Equity method investments

The following summarizes the operating results for the three and nine months ended September 30, 2013 and 2012, respectively, for earnings in our equity method investments:

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
(in millions) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Project revenue |  |  |  |  |  |  |  |  |  |  |  |  |
Chambers |  | $ | 13.4 |  | $ | 12.2 |  | $ | 40.0 |  | $ | 40.1 |
Other |  |  | 37.2 |  |  | 39.4 |  |  | 117.7 |  |  | 118.4 |
|  |  | 50.6 |  |  | 51.6 |  |  | 157.7 |  |  | 158.5 |
Project expenses |  |  |  |  |  |  |  |  |  |  |  |  |
Chambers |  |  | 10.1 |  |  | 9.6 |  |  | 30.8 |  |  | 28.1 |
Other |  |  | 29.3 |  |  | 38.5 |  |  | 97.5 |  |  | 110.8 |
|  |  | 39.4 |  |  | 48.1 |  |  | 128.3 |  |  | 138.9 |
Project other income (expense) |  |  |  |  |  |  |  |  |  |  |  |  |
Chambers |  |  | (0.7 | ) |  | 0.2 |  |  | (1.8 | ) |  | (1.4 | )
Other |  |  | 28.6 |  |  | 0.3 |  |  | 27.4 |  |  | (5.8 | )
|  |  | 27.9 |  |  | 0.5 |  |  | 25.6 |  |  | (7.2 | )
Project income |  |  |  |  |  |  |  |  |  |  |  |  |
Chambers |  |  | 2.6 |  |  | 2.8 |  |  | 7.4 |  |  | 10.6 |
Other |  |  | 36.5 |  |  | 1.2 |  |  | 47.6 |  |  | 1.8 |
|  |  | 39.1 |  |  | 4.0 |  |  | 55.0 |  |  | 12.4 |

4. Goodwill

Our goodwill balance was $296.3 million and $334.7 million as of September 30, 2013 and December 31, 2012, respectively. We recorded $331.1 million of goodwill in connection with the acquisition of Capital Power Income L.P. (the "Partnership") in 2011 and $3.5 million associated with the step-up acquisition of Rollcast in March 2010.

We apply an accounting standard under which goodwill has an indefinite life and is not amortized. Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating segments for which discrete financial information is available. Based on a prolonged decline in our market capitalization, we determined that it was appropriate to initiate a test of goodwill to determine if the fair value of each of our reporting units' goodwill does not exceed their carrying amounts. The impairment analysis was performed as of August 31, 2013. For reporting units that failed step 1 of the goodwill impairment test, we performed a step 2 test to quantify the amount, if any, of non-cash impairment to record.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

4. Goodwill (Continued)

Based on the results of our impairment analysis, it was determined that goodwill was impaired at the Kenilworth reporting unit (Northeast segment) and the Naval Station, Naval Training Center and North Island reporting units ("The Naval reporting units") (Southwest segment). The total impairment recorded in the three months ended September 30, 2013 was $34.9 million.

The $30.8 million impairment at Kenilworth was due to lower forecasted capacity and energy prices compared to the assumptions at the time of the acquisition in November 2011. When performing our step 2 quantitative analysis, the increase in the intangible value associated with the new Energy Service Agreement ("ESA") entered into in July 2013 resulted in a lower implied goodwill value. At the time of its acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Kenilworth project were valued assuming a merchant basis for the period subsequent to the expiration of the project's original PPA in July 2012. As discussed above, these forecasted energy revenues on a merchant basis were higher than the current forecasted energy prices subsequent to the expiration of the new ESA. The $4.1 million impairment at the Naval reporting units was primarily due to increased uncertainty, not assumed at the time of the reporting units acquisition in 2011, in our ability to extend two of the projects lease and steam agreements upon their expiration. In addition, lower currently forecasted capacity and energy prices in California after the expiration of the PPAs compared to the forecast at the time of the acquisition in 2011 result in a lower business enterprise value which resulted in a lower implied goodwill value.

During the three months ended June 30, 2013, we recorded a $3.5 million impairment of goodwill at Rollcast which is a component of our Un-allocated corporate segment. We determined, based on the results of the two-step process, that the carrying amount of goodwill exceeded the implied fair value of goodwill. We also wrote-off $1.4 million of capitalized development costs at Rollcast related to the Greenway development project. The determination to impair goodwill and write-off the capitalized development costs was based on the reduced expectation of the Greenway project being further developed.

The following table is a roll-forward of goodwill for the nine months ended September 30, 2013:

(in millions) |  | Northeast |  | Northwest |  | Southwest |  | Un-allocated corporate |  | Total |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Balance at December 31, 2012 |  | $ | 135.3 |  | $ | 138.3 |  | $ | 57.6 |  | $ | 3.5 |  | $ | 334.7 |
Impairment of goodwill |  |  | (30.8 | ) |  | — |  |  | (4.1 | ) |  | (3.5 | ) |  | (38.4 | )
Balance at September 30, 2013 |  | $ | 104.5 |  | $ | 138.3 |  | $ | 53.5 |  | $ | — |  | $ | 296.3 |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

5. Long-term debt

Long-term debt consists of the following:

(in millions) |  | September 30, 2013 |  | December 31, 2012 |  | Interest Rate
--- | --- | --- | --- | --- | --- | ---
Recourse Debt: |  |  |  |  |  |  |  |
Senior unsecured notes, due 2018 |  | $ | 460.0 |  | $ | 460.0 |  | 9.0%
Senior unsecured notes, due June 2036 (Cdn$210.0) |  |  | 203.8 |  |  | 211.1 |  | 6.0%
Senior unsecured notes, due July 2014 |  |  | 190.0 |  |  | 190.0 |  | 5.9%
Series A senior unsecured notes, due August 2015 |  |  | 150.0 |  |  | 150.0 |  | 5.9%
Series B senior unsecured notes, due August 2017 |  |  | 75.0 |  |  | 75.0 |  | 6.0%
Non-Recourse Debt: |  |  |  |  |  |  |  |
Epsilon Power Partners term facility, due 2019 |  |  | 31.2 |  |  | 33.5 |  | 7.4%
Cadillac term loan, due 2025 |  |  | 36.0 |  |  | 37.8 |  | 6.0% – 8.0%
Piedmont construction loan, due 2013 |  |  | 76.6 | (1) |  | 127.4 |  | Libor plus 3.5%
Meadow Creek term loan, due 2024 |  |  | 171.4 | (2) |  | 208.7 |  | 2.9% – 5.1%
Rockland term loan, due 2027 |  |  | 85.8 |  |  | 86.5 |  | 6.4%
Other long-term debt |  |  | 1.0 |  |  | 0.3 |  | 5.5% – 6.7%
Less: current maturities |  |  | (206.7 | ) |  | (121.2 | ) |
Total long-term debt |  | $ | 1,274.1 |  | $ | 1,459.1 |  |

Current maturities consist of the following:

|  | September 30, 2013 |  | December 31, 2012 |  | Interest Rate
--- | --- | --- | --- | --- | --- | ---
Current Maturities: |  |  |  |  |  |  |  |
Senior unsecured notes, due July 2014 |  | $ | 190.0 |  |  | — |  | 5.9%
Epsilon Power Partners term facility, due 2019 |  |  | 4.5 |  |  | 3.0 |  | 7.4%
Cadillac term loan, due 2025 |  |  | 2.1 |  |  | 2.4 |  | 6.0% – 8.0%
Piedmont construction loan, due 2013 |  |  | 4.4 | (1) |  | 55.1 |  | Libor plus 3.5%
Meadow Creek term loan, due 2024 |  |  | 4.1 | (2) |  | 59.5 |  | 2.9% – 5.1%
Rockland term loan, due 2027 |  |  | 1.4 |  |  | 1.2 |  | 6.4%
Other short-term debt |  |  | 0.2 |  |  | — |  | 5.5 – 6.7%
Total current maturities |  | $ | 206.7 |  | $ | 121.2 |  |

(1)
  The terms of the Piedmont project-level debt financing include a $51.0 million bridge loan and an $82.0 million construction loan ($76.6 million at September 30, 2013) that is expected to convert to a term loan in the fourth quarter of 2013. On April 19, 2013, Piedmont achieved commercial operations and submitted an application under the 1603 federal grant program to recover approximately 30% of its capital cost. The grant application was approved and we received a $49.5 million grant from the U.S. Treasury in July 2013. Upon receipt of the grant, we repaid in full the $51.0 million bridge loan with the proceeds of the grant and a $1.5 million contribution from us to cover the shortfall resulting from the federal sequester on spending. We expect to commence the repayment of the term loan in the fourth quarter of 2013.
(2)
  Meadow Creek debt consists of $171.4 million term loan and a $56.5 million cash grant loan. The cash grant loan was repaid in April 2013 with $49.0 million of proceeds from the 1603 grant with the U.S. Treasury, $4.7 million from the former owners to cover the shortfall resulting from the federal sequester on spending and a $2.8 million contribution from

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

5. Long-term debt (Continued)

us to cover the shortfall from lower grant-eligible costs than anticipated, primarily as a result of a lower project cost versus budget.

Non-Recourse Debt

Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project-level debt generally amortizes during the term of the respective revenue generating contracts of the projects. The loans have certain financial covenants that must be met.

Senior Credit Facility

At September 30, 2013, we had a senior credit facility of $150.0 million on a senior secured basis, which was amended on August 2, 2013, as further described below (the "senior credit facility"). All $150.0 million of capacity could have been utilized for letters of credit and a sublimit of $25.0 million could have been utilized for other borrowings. At September 30, 2013, the senior credit facility was undrawn and the applicable LIBOR margin was 4.25%. At September 30, 2013, $91.2 million was issued in letters of credit, but not drawn, to support contractual credit requirements at several of our projects.

On August 2, 2013 we entered into an amendment to our prior senior credit facility with our lenders (the "amendment"). The most significant changes to the prior senior credit facility as a result of the amendment include the following:

•
  a decrease in capacity from $300 million to $150 million, all of which may be utilized for letters of credit (as compared to the previous $200 million that could have been utilized for letters of credit) and a sublimit of $25 million which may be utilized for other borrowings;
•
  a requirement to cash collateralize outstanding letters of credit in an amount equal to the excess above $125 million if the aggregate amount of letters of credit and borrowings outstanding under the senior credit facility exceeds $125 million;
•
  a requirement to maintain at all times unrestricted cash and cash equivalents of at least $75 million (inclusive of any cash collateral provided as described above), which shall be pledged to the lenders as security for the senior credit facility;
•
  an amendment to the maximum permissible Consolidated Total Net Debt to Consolidated EBITDA (each as defined in the senior credit facility) to 7.75 to 1.00 (as compared to a prior ratio of 7.50 to 1.00 declining to 7.00 to 1.00 over time);
•
  an amendment to the minimum permissible Consolidated EBITDA to Consolidated Interest Expense (each as defined in the senior credit facility) ratio to 1.60 to 1.00 (as compared to a prior ratio of 2.25 to 1.00);
•
  a requirement to pay a commitment fee of between 0.75% and 1.75% per year based on a percentage of the amount committed under the senior credit facility, which fee varies based on our unsecured debt rating (at September 30, 2013, the applicable commitment fee is 1.50%); and
•
  an amendment to the maturity date from November 4, 2015 to March 4, 2015.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

5. Long-term debt (Continued)

Among other restrictions set forth in the senior credit facility, we are restricted from paying cash dividends to our shareholders if we do not comply with the financial covenants specified above. The senior credit facility is secured by pledges of certain assets and interests in certain subsidiaries. The prior senior credit facility contained customary representations, warranties, terms and conditions, and covenants, certain of which were amended in connection with the amendment to the senior credit facility. The covenants in the senior credit facility limit our ability to, among other things, incur additional indebtedness, merge or consolidate with others, make acquisitions, change our business and sell or dispose of assets. These covenants also include limitations on investments, limitations on dividends and other restricted payments, limitations on entering into certain types of restrictive agreements, limitations on transactions with affiliates and limitations on the use of proceeds from the senior credit facility. Specifically, under the senior credit facility, we are effectively only permitted to make voluntary prepayments or repurchases of our outstanding debt (including for these purposes subsidiary debt guaranteed by us) from the proceeds of debt permitted to be incurred to refinance that outstanding debt or during the 60-day period preceding the maturity of that outstanding debt. Under the prior senior credit facility, we had the right generally to repurchase substantially more of our outstanding debt issuances, subject to the satisfaction of certain conditions. In the amendment, the lenders also consented to (i) our previously announced sale of Delta-Person and (ii) the sale of AP Onondaga, LLC, Onondaga Renewables, LLC and their property.

Borrowings under the senior credit facility are available in U.S. dollars and Canadian dollars and bear interest at a variable rate equal to the US Prime Rate, the Eurocurrency LIBOR Rate or the Cdn. Prime Rate (each as defined in the senior credit facility), as applicable, plus a margin of between 2.75% and 4.75% that varies based on our unsecured debt rating. At September 30, 2013, the applicable margin for loans bearing interest at the Eurocurrency LIBOR Rate and for outstanding letters of credit was 4.25%. The foregoing summary is qualified in its entirety by reference to the senior credit facility, which was filed as an exhibit to our Current Report on Form 8-K on August 5, 2013 and is incorporated by reference as an exhibit to this Quarterly Report on Form 10-Q.

6. Fair value of financial instruments

The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of September 30, 2013 and December 31, 2012.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

6. Fair value of financial instruments (Continued)

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

|  | September 30, 2013 |
--- | --- | --- | ---
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 170.7 |  | $ | — |  | $ | — |  | $ | 170.7 |
Restricted cash |  |  | 119.8 |  |  | — |  |  | — |  |  | 119.8 |
Derivative instruments asset |  |  | — |  |  | 9.8 |  |  | — |  |  | 9.8 |
Total |  | $ | 290.5 |  | $ | 9.8 |  | $ | — |  | $ | 300.3 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative instruments liability |  | $ | — |  | $ | 119.9 |  | $ | — |  | $ | 119.9 |
Total |  | $ | — |  | $ | 119.9 |  | $ | — |  | $ | 119.9 |

|  | December 31, 2012 |
--- | --- | --- | ---
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 60.2 |  | $ | — |  | $ | — |  | $ | 60.2 |
Restricted cash |  |  | 28.6 |  |  | — |  |  | — |  |  | 28.6 |
Derivative instruments asset |  |  | — |  |  | 20.6 |  |  | — |  |  | 20.6 |
Total |  | $ | 88.8 |  | $ | 20.6 |  | $ | — |  | $ | 109.4 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative instruments liability |  | $ | — |  | $ | 151.1 |  | $ | — |  | $ | 151.1 |
Total |  | $ | — |  | $ | 151.1 |  | $ | — |  | $ | 151.1 |

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

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

We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of September 30, 2013, the credit valuation adjustments resulted in a $13.0 million net increase in fair value, which consists of a $0.6 million pre-tax gain in other comprehensive income and a $12.4 million gain in change in fair value of derivative instruments. As of December 31, 2012, the credit valuation adjustments resulted in an $18.4 million net increase in fair value, which consists of a $1.0 million pre-tax gain in other comprehensive income, a $13.8 million gain in change in fair value of derivative

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

6. Fair value of financial instruments (Continued)

instruments and a $3.6 million increase related to interest rate swaps assumed in the acquisition of Ridgeline.

7. 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 each reporting period. For certain contracts designated as cash flow hedges, 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. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

For derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings. The guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.

Gas purchase agreements

On March 12, 2012, we discontinued the application of the normal purchase normal sales ("NPNS") exemption on gas purchase agreements at our North Bay, Kapuskasing and Nipigon projects. On that date, we entered into an agreement with a third party that resulted in the gas purchase agreements no longer qualifying for the NPNS exemption. The agreements at North Bay and Kapuskasing expire on December 31, 2016. These gas purchase agreements 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.

In May 2012, the Nipigon project entered into a long-term contract for the purchase of natural gas beginning on January 1, 2013 and expiring on December 31, 2022. This contract is accounted for as a derivative financial instrument and is recorded in the consolidated balance sheet at fair value at September 30, 2013 and December 31, 2012. Changes in the fair market value of the contract are recorded in the consolidated statements of operations.

In April, June and August 2013, the Tunis project entered into contracts for the purchase of natural gas beginning on October 1, 2013 and expiring on March 31, 2014. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value as of September 30, 2013. Changes in the fair market value of the contracts are recorded in the consolidated statement of operations.

Natural gas swaps

Our strategy to mitigate a portion of the 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.

The operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. We have entered into natural gas

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Derivative instruments and hedging activities (Continued)

swaps to effectively fix the price of 3.2 million Mmbtu of future natural gas purchases, or approximately 74% of our share of the expected natural gas purchases at the project during 2014 and 2015. We also entered into natural gas swaps to effectively fix the price of 1.3 million Mmbtu of future natural gas purchases representing approximately 38% of our share of the expected natural gas purchases at the project during 2016 and 2017.

Interest rate swaps

Cadillac Renewable Energy, LLC ("Cadillac") has an interest rate swap agreement that effectively fixes the interest rate at 6.0% from February 16, 2011 to February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss).

Piedmont has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until November 2017, the fixed rate of the swap is 4.5% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.5% from the maturity of the debt in November 2017 until November 2030. The notional amounts of the interest rate swap agreements match the estimated outstanding principal balance of Piedmont's cash grant bridge loan and the construction loan facility that will convert to a term loan. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.

Epsilon Power Partners ("Epsilon") has an interest rate swap to economically fix the exposure to changes in interest rates related to the variable-rate non-recourse debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 7.4% and has a maturity date of July 2019. The notional amount of the swap matches the outstanding principal balance over the remaining life of Epsilon's debt. This interest rate swap agreement is not designated as a hedge and changes in its fair market value are recorded in the consolidated statements of operations.

Rockland Wind Farm, LLC ("Rockland") entered into interest rate swaps to manage interest rate risk exposure. These swaps effectively modify the project's exposure by converting the project's floating rate debt to a fixed basis. The interest rate swaps are with various counterparties and swap 100% of the expected interest payments from floating LIBOR to fixed rates structured in two tranches. The first tranche is for the notional amount due on the term loan commencing on December 30, 2011 and ending December 31, 2026 and fixes the interest rate at 4.2% plus an applicable margin of 2.3% - 2.8%. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2026 and ends on December 31, 2031, fixing the interest rate at 7.8%. The interest rate swap agreements are not designated as a hedge and changes in their fair market value are recorded in the consolidated statements of operations.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Derivative instruments and hedging activities (Continued)

The Meadow Creek project ("Meadow Creek") has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements effectively converted 75% of the floating rate debt to a fixed interest rate of 2.3% plus an applicable margin of 2.8% - 3.3% from December 31, 2012 to December 31, 2024. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2024 and ends on December 31, 2030, fixing the interest rate at 7.2%. The interest rate swaps were both executed on September 17, 2012 and expire on December 31, 2024 and December 31, 2030, respectively. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.

Foreign currency forward contracts

We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars but we pay dividends to shareholders, if and when declared by the board of directors, and interest on corporate level long-term debt and convertible debentures, predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on future payments of dividends to shareholders, if and when declared by the board of directors. We have executed this strategy utilizing cash flows from our projects that generate Canadian dollars and by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge an average of approximately 71% of any dividend and expected long-term debt and convertible debenture interest payments through 2015. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. At September 30, 2013, the forward contracts consist of contracts assumed in our acquisition of the Partnership with various expiration dates through December 2015 to purchase a total of Cdn$34.9 million at an average exchange rate of Cdn$1.108 per U.S. dollar. It is our intention to periodically consider extending or terminating these forward contracts.

In April 2013, we terminated various foreign currency forward contracts with expiration dates through June 2015 assumed in our acquisition of the Partnership resulting in proceeds and a realized gain of $9.4 million.

Volume of forecasted transactions

We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption as of September 30, 2013 and December 31, 2012:

|  | Units |  | September 30, 2013 |  | December 31, 2012 |
--- | --- | --- | --- | --- | --- | --- | ---
Natural gas swaps |  | Natural Gas (Mmbtu) |  |  | 5.6 |  |  | 10.6 |
Gas purchase agreements |  | Natural Gas (GJ) |  |  | 43.9 |  |  | 49.8 |
Interest rate swaps |  | Interest (US$) |  |  | 164.4 |  |  | 172.0 |
Foreign currency forwards |  | Cdn$ |  |  | 34.9 |  |  | 176.6 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Derivative instruments and hedging activities (Continued)

Fair value of derivative instruments

The fair value of our derivative assets and liabilities under counterparty master netting agreement are disclosed net on the consolidated balance sheets at September 30, 2013 and December 31, 2012. In the following table, we have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:

|  | September 30, 2013 |
--- | --- | --- | ---
|  | Derivative Assets |  | Derivative Liabilities |
Derivative instruments designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  | $ | — |  | $ | 1.3 |
Interest rate swaps long-term |  |  | — |  |  | 3.2 |
Total derivative instruments designated as cash flow hedges |  |  | — |  |  | 4.5 |
Derivative instruments not designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  |  | — |  |  | 7.5 |
Interest rate swaps long-term |  |  | 7.9 |  |  | 12.6 |
Foreign currency forward contracts current |  |  | 0.6 |  |  | 0.3 |
Foreign currency forward contracts long-term |  |  | 1.6 |  |  | — |
Natural gas swaps current |  |  | — |  |  | 1.2 |
Natural gas swaps long-term |  |  | — |  |  | 3.9 |
Gas purchase agreements current |  |  | — |  |  | 22.8 |
Gas purchase agreements long-term |  |  | — |  |  | 67.4 |
Total derivative instruments not designated as cash flow hedges |  |  | 10.1 |  |  | 115.7 |
Total derivative instruments |  | $ | 10.1 |  | $ | 120.2 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Derivative instruments and hedging activities (Continued)

|  | December 31, 2012 |
--- | --- | --- | ---
|  | Derivative Assets |  | Derivative Liabilities |
Derivative instruments designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  | $ | — |  | $ | 1.3 |
Interest rate swaps long-term |  |  | — |  |  | 5.2 |
Total derivative instruments designated as cash flow hedges |  |  | — |  |  | 6.5 |
Derivative instruments not designated as cash flow hedges: |  |  |  |  |  |  |
Interest rate swaps current |  |  | — |  |  | 7.3 |
Interest rate swaps long-term |  |  | 0.1 |  |  | 27.7 |
Foreign currency forward contracts current |  |  | 9.5 |  |  | — |
Foreign currency forward contracts long-term |  |  | 11.0 |  |  | — |
Natural gas swaps current |  |  | — |  |  | — |
Natural gas swaps long-term |  |  | 0.1 |  |  | 3.9 |
Gas purchase agreements current |  |  | 0.1 |  |  | 24.5 |
Gas purchase agreements long-term |  |  | — |  |  | 81.4 |
Total derivative instruments not designated as cash flow hedges |  |  | 20.8 |  |  | 144.8 |
Total derivative instruments |  | $ | 20.8 |  | $ | 151.3 |

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:

(in millions) Three months ended September 30, 2013 |  | Interest Rate Swaps |  | Natural Gas Swaps |  | Total |
--- | --- | --- | --- | --- | --- | --- | ---
Accumulated OCI balance at June 30, 2013 |  | $ | (0.4 | ) | $ | — |  | $ | (0.4 | )
Change in fair value of cash flow hedges |  |  | (0.1 | ) |  | — |  |  | (0.1 | )
Realized from OCI during the period |  |  | 0.2 |  |  | — |  |  | 0.2 |
Accumulated OCI balance at September 30, 2013 |  | $ | (0.3 | ) | $ | — |  | $ | (0.3 | )

(in millions) Three months ended September 30, 2012 |  | Interest Rate Swaps |  | Natural Gas Swaps |  | Total |
--- | --- | --- | --- | --- | --- | --- | ---
Accumulated OCI balance at June 30, 2012 |  | $ | (1.7 | ) | $ | 0.2 |  | $ | (1.5 | )
Change in fair value of cash flow hedges |  |  | (0.3 | ) |  | — |  |  | (0.3 | )
Realized from OCI during the period |  |  | 0.2 |  |  | (0.1 | ) |  | 0.1 |
Accumulated OCI balance at September 30, 2012 |  | $ | (1.8 | ) | $ | 0.1 |  | $ | (1.7 | )

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Derivative instruments and hedging activities (Continued)

(in millions) Nine months ended September 30, 2013 |  | Interest Rate Swaps |  | Natural Gas Swaps |  | Total |
--- | --- | --- | --- | --- | --- | --- | ---
Accumulated OCI balance at December 31, 2012 |  | $ | (1.5 | ) | $ | 0.1 |  | $ | (1.4 | )
Change in fair value of cash flow hedges |  |  | 0.5 |  |  | — |  |  | 0.5 |
Realized from OCI during the period |  |  | 0.7 |  |  | (0.1 | ) |  | 0.6 |
Accumulated OCI balance at September 30, 2013 |  | $ | (0.3 | ) | $ | — |  | $ | (0.3 | )

(in millions) Nine months ended September 30, 2012 |  | Interest Rate Swaps |  | Natural Gas Swaps |  | Total |
--- | --- | --- | --- | --- | --- | --- | ---
Accumulated OCI balance at December 31, 2011 |  | $ | (1.7 | ) | $ | 0.3 |  | $ | (1.4 | )
Change in fair value of cash flow hedges |  |  | (0.8 | ) |  | — |  |  | (0.8 | )
Realized from OCI during the period |  |  | 0.7 |  |  | (0.2 | ) |  | 0.5 |
Accumulated OCI balance at September 30, 2012 |  | $ | (1.8 | ) | $ | 0.1 |  | $ | (1.7 | )

Impact of derivative instruments on the consolidated statements of operations

The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:

|  |  |  | Three months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | Classification of (gain) loss recognized in income |
|  | 2013 |  | 2012 |
Gas purchase agreements |  | Fuel |  | $ | 7.6 |  | $ | 13.3 |
Foreign currency forwards |  | Foreign exchange gain |  |  | (1.1 | ) |  | (2.1 | )
Interest rate swaps |  | Interest, net |  |  | 2.7 |  |  | 1.2 |

|  |  |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | Classification of (gain) loss recognized in income |
|  | 2013 |  | 2012 |
Gas purchase agreements |  | Fuel |  | $ | 38.0 |  | $ | 29.3 |
Foreign currency forwards |  | Foreign exchange gain |  |  | (14.4 | ) |  | (17.3 | )
Interest rate swaps |  | Interest, net |  |  | 9.4 |  |  | 3.4 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Derivative instruments and hedging activities (Continued)

The following table summarizes the unrealized gains and losses resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:

|  |  |  | Three months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | Classification of (gain) loss recognized in income |
|  | 2013 |  | 2012 |
Natural gas swaps |  | Change in fair value of derivatives |  | $ | 0.6 |  | $ | (1.0 | )
Gas purchase agreements |  | Change in fair value of derivatives |  |  | 3.6 |  |  | (10.0 | )
Interest rate swaps |  | Change in fair value of derivatives |  |  | (0.7 | ) |  | 0.3 |
Total change in fair value of derivative instruments |  |  |  | $ | 3.5 |  | $ | (10.7 | )
Foreign currency forwards |  | Foreign exchange loss (gain) |  | $ | (0.2 | ) | $ | (4.7 | )

|  |  |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | Classification of (gain) loss recognized in income |
|  | 2013 |  | 2012 |
Natural gas swaps |  | Change in fair value of derivatives |  | $ | 1.4 |  | $ | (0.2 | )
Gas purchase agreements |  | Change in fair value of derivatives |  |  | (12.0 | ) |  | (49.3 | )
Interest rate swaps |  | Change in fair value of derivatives |  |  | (22.8 | ) |  | (1.8 | )
Total change in fair value of derivative instruments |  |  |  | $ | (33.4 | ) | $ | (51.3 | )
Foreign currency forwards |  | Foreign exchange loss (gain) |  | $ | 18.5 |  | $ | 8.2 |

8. Income taxes

Income tax benefit from continuing operations for the nine months ended September 30, 2013 was $1.9 million. The difference between the actual tax benefit of $1.9 million and the expected income tax benefit of $7.0 million, based on the Canadian enacted statutory rate of 25%, is primarily due to a goodwill impairment of $13.7 million, a $4.5 million increase in the valuation allowance, $6.2 million in dividend withholding and preferred share taxes, and $5.2 million of changes in estimates at joint venture projects. This is partially offset by $19.4 million related to 1603 Treasury grant proceeds, $3.9 million of foreign exchange, and $1.0 million of other permanent differences.

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Current income tax expense |  | $ | 5.4 |  | $ | 1.9 |  | $ | 10.8 |  | $ | 6.1 |
Deferred tax (benefit) expense |  |  | (5.4 | ) |  | 1.2 |  |  | (12.7 | ) |  | (25.2 | )
Total income tax (benefit) expense |  | $ | — |  | $ | 3.1 |  | $ | (1.9 | ) | $ | (19.1 | )

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

8. Income taxes (Continued)

As of September 30, 2013, we have recorded a valuation allowance of $122.0 million. The amount is comprised primarily of provisions against Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

9. Employee incentive programs

Long-Term Incentive Program

The following table summarizes the changes in LTIP notional units during the nine months ended September 30, 2013:

(Units in thousands) |  | Units |  | Grant Date Weighted-Average Price per Unit |
--- | --- | --- | --- | --- | ---
Outstanding at December 31, 2012 |  |  | 492,535 |  | $ | 13.88 |
Granted |  |  | 597,031 |  |  | 4.91 |
Reinvested |  |  | 45,344 |  |  | 9.12 |
Forfeited |  |  | (138,473 | ) |  | 8.88 |
Vested |  |  | (202,696 | ) |  | 13.48 |
Outstanding at September 30, 2013 |  |  | 793,741 |  | $ | 7.76 |

Certain awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies and, in some cases, Project Adjusted EBITDA per common share compared to budget. Compensation expense for notional units granted in 2013 is recorded net of estimated forfeitures. See Note 14 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2012 for further details. Cash payments made for vested notional units for the nine months ended September 30, 2013 was $0.9 million. Compensation expense for LTIP was $0.4 million and $1.7 million for the three and nine months end September 30, 2013, respectively.

The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period for awards with market conditions included the following assumptions as of September 30, 2013 and December 31, 2012:

|  | September 30, 2013 |  | December 31, 2012
--- | --- | --- | --- | ---
Weighted average risk free rate of return |  | 0.0 – 0.5% |  | 0.1 – 0.3%
Dividend yield |  | 9.0% |  | 10.1%
Expected volatility—Atlantic Power |  | 42.2% |  | 22.5%
Expected volatility—peer companies |  | 10.6 – 96.3% |  | 11.9 – 97.1%
Weighted average remaining measurement period |  | 2.1 years |  | 1.4 years

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

10. Basic and diluted earnings (loss) per share

Basic earnings (loss) per share are calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share are computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2013. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP. The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and nine months ended September 30, 2013 and 2012:

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Numerator: |  |  |  |  |  |  |  |  |  |  |  |  |
Loss from continuing operations attributable to Atlantic Power Corporation |  | $ | (40.9 | ) | $ | (26.5 | ) | $ | (31.8 | ) | $ | (103.7 | )
Income (loss) from discontinued operations, net of tax |  |  | (0.4 | ) |  | 19.0 |  |  | (6.1 | ) |  | 48.8 |
Net loss attributable to Atlantic Power Corporation |  | $ | (41.3 | ) | $ | (7.5 | ) | $ | (37.9 | ) | $ | (54.9 | )
Denominator: |  |  |  |  |  |  |  |  |  |  |  |  |
Weighted average basic shares outstanding |  |  | 120.0 |  |  | 119.0 |  |  | 119.8 |  |  | 115.4 |
Dilutive potential shares: |  |  |  |  |  |  |  |  |  |  |  |  |
Convertible debentures |  |  | 27.7 |  |  | 20.5 |  |  | 27.7 |  |  | 15.7 |
LTIP notional units |  |  | 0.8 |  |  | 0.5 |  |  | 0.7 |  |  | 0.5 |
Potentially dilutive shares |  |  | 148.5 |  |  | 140.0 |  |  | 148.2 |  |  | 131.6 |
Diluted loss per share from continuing operations attributable to Atlantic Power Corporation |  | $ | (0.34 | ) | $ | (0.22 | ) | $ | (0.27 | ) | $ | (0.90 | )
Diluted earnings (loss) per share from discontinued operations |  |  | (0.00 | ) |  | 0.16 |  |  | (0.05 | ) |  | 0.42 |
Diluted loss per share attributable to Atlantic Power Corporation |  | $ | (0.34 | ) | $ | (0.06 | ) | $ | (0.32 | ) | $ | (0.48 | )

Potentially dilutive shares from convertible debentures and LTIP notional units have been excluded from fully diluted shares for the three and nine months ended September 30, 2013 and 2012 because their impact would be anti-dilutive.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

11. Assets held for sale and discontinued operations

During the three months ended September 30, 2013, we initiated and approved a plan to sell our 60% interest in Rollcast. Rollcast is classified as held for sale and its net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the three and nine months ended September 30, 2013 and 2012. Rollcast's loss from discontinued operations includes a $3.5 million impairment of goodwill charge and a $1.4 million impairment of intangible asset charge recorded in the three months ended June 30, 2013.

The Florida Projects and Path 15 were sold on April 12, 2013 and April 30, 2013, respectively. Accordingly, the projects' net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012.

The following tables summarize the revenue, income (loss) from operations, and income tax expense of Rollcast, Path 15 and the Florida Projects for the three and nine months ended September 30, 2013 and 2012:

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
(in millions) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Revenue |  | $ | — |  | $ | 55.2 |  | $ | 71.6 |  | $ | 158.2 |
Income (loss) from operations of discontinued businesses |  |  | (0.4 | ) |  | 19.5 |  |  | (5.3 | ) |  | 49.7 |
Income tax expense |  |  | — |  |  | 0.5 |  |  | 0.8 |  |  | 0.9 |
Income (loss) from operations of discontinued businesses, net of tax |  | $ | (0.4 | ) | $ | 19.0 |  | $ | (6.1 | ) | $ | 48.8 |

Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for Rollcast, the Florida Projects and Path 15 were $0.0 and $0.16 for the three month periods ended September 30, 2013 and 2012, respectively, and $(0.05) and $0.42 for the nine month periods ended September 30, 2013 and 2012, respectively.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

11. Assets held for sale and discontinued operations (Continued)

The assets and liabilities of these projects classified as assets held for sale in the accompanying consolidated balance sheets as of September 30, 2013 and December 31, 2012 consisted of the following:

(in millions) |  | September 30, 2013 |  | December 31, 2012 |
--- | --- | --- | --- | --- | ---
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 0.3 |  | $ | 6.5 |
Restricted cash |  |  | — |  |  | 12.6 |
Accounts receivable |  |  | 0.1 |  |  | 21.9 |
Other current assets |  |  | — |  |  | 6.3 |
|  |  | 0.4 |  |  | 47.3 |
Non-current assets: |  |  |  |  |  |  |
Plant, Property & Equipment |  |  | 0.1 |  |  | 111.9 |
Transmission system rights |  |  | — |  |  | 172.4 |
Goodwill |  |  | — |  |  | 8.9 |
Other assets |  |  | — |  |  | 10.9 |
Assets from discontinued operations |  |  | 0.5 |  |  | 351.4 |
Current liabilities: |  |  |  |  |  |  |
Accounts payable and other accrued liabilities |  | $ | 0.1 |  | $ | 16.5 |
Current portion of long-term debt |  |  | — |  |  | 14.3 |
Current portion of derivative instruments liability |  |  | — |  |  | 20.0 |
Other liabilities |  |  | — |  |  | 0.5 |
|  |  | 0.1 |  |  | 51.3 |
Long-term liabilities |  |  |  |  |  |  |
Long-term debt |  |  | — |  |  | 137.7 |
Other long-term liabilities |  |  | — |  |  | — |
Liabilities from discontinued operations |  |  | 0.1 |  |  | 189.0 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

12. Equity

The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power, preferred shares issued by a subsidiary company, noncontrolling interests and total equity for the nine months ended September 30, 2013 and 2012:

|  | Nine months ended September 30, 2013 |
--- | --- | --- | ---
(in millions) |  | Total Atlantic Power Corporation Shareholders' Equity |  | Preferred shares issued by a subsidiary company |  | Noncontrolling Interests |  | Total Equity |
Balance at January 1 |  | $ | 729.7 |  | $ | 221.3 |  | $ | 235.4 |  | $ | 1,186.4 |
Net income (loss) |  |  | (37.9 | ) |  | 9.5 |  |  | (3.3 | ) |  | (31.7 | )
Realized and unrealized loss on hedging activities, net of tax |  |  | 1.1 |  |  | — |  |  | — |  |  | 1.1 |
Foreign currency translation adjustment, net of tax |  |  | (19.3 | ) |  | — |  |  | — |  |  | (19.3 | )
Common shares issued for LTIP |  |  | 1.2 |  |  | — |  |  | — |  |  | 1.2 |
Contribution by and sale of noncontrolling interst |  |  | — |  |  | — |  |  | 44.6 |  |  | 44.6 |
Costs associated with tax equity raise |  |  | (0.9 | ) |  | — |  |  | — |  |  | (0.9 | )
Dividends paid to noncontrolling interest |  |  | — |  |  | — |  |  | (4.4 | ) |  | (4.4 | )
Dividends declared on common shares |  |  | (46.5 | ) |  | — |  |  | — |  |  | (46.5 | )
Dividends declared on preferred shares of a subsidiary company |  |  | — |  |  | (9.5 | ) |  | — |  |  | (9.5 | )
Balance at September 30 |  | $ | 627.4 |  | $ | 221.3 |  | $ | 272.3 |  | $ | 1,121.0 |

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

12. Equity (Continued)

|  | Nine months ended September 30, 2012 |
--- | --- | --- | ---
|  | Total Atlantic Power Corporation Shareholders' Equity |  | Preferred shares issued by a subsidiary company |  | Noncontrolling Interests |  | Total Equity |
Balance at January 1 |  | $ | 891.5 |  | $ | 221.3 |  | $ | 3.0 |  | $ | 1,115.8 |
Net income (loss) |  |  | (54.9 | ) |  | 9.8 |  |  | (0.7 | ) |  | (45.8 | )
Realized and unrealized loss on hedging activities, net of tax |  |  | (0.3 | ) |  | — |  |  | — |  |  | (0.3 | )
Foreign currency translation adjustment, net of tax |  |  | 22.6 |  |  | — |  |  | — |  |  | 22.6 |
Common shares issuance, net of costs |  |  | 67.8 |  |  | — |  |  | — |  |  | 67.8 |
Common shares issued for LTIP |  |  | 1.5 |  |  | — |  |  | — |  |  | 1.5 |
Dividends declared on common shares |  |  | (99.0 | ) |  | — |  |  | — |  |  | (99.0 | )
Dividends declared on preferred shares of a subsidiary company |  |  | — |  |  | (9.8 | ) |  | — |  |  | (9.8 | )
Balance at September 30 |  | $ | 829.2 |  | $ | 221.3 |  | $ | 2.3 |  | $ | 1,052.8 |

13. Segment and geographic information

Our operating segments are Northeast, Northwest, Southeast, Southwest and Un-allocated Corporate. The segment classified as Un-allocated Corporate includes activities that support the executive offices, capital structure and costs of being a public registrant in the United States and Canada. Un-allocated Corporate also includes Rollcast, a 60% owned company, which develops, owns and operates renewable power plants that use wood or biomass fuel, and for which we initiated and approved a plan to sell, and Ridgeline, which develops and operates wind and solar power projects. These costs are not allocated to the operating segments when determining segment profit or loss.

We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. Rollcast, a component of the Un-allocated Corporate segment, Path 15, a component of the Southwest segment, and the Florida projects, which are components of the Southeast segment, are included in the income from discontinued operations line item in the table below. We have adjusted prior periods to reflect this reclassification. A reconciliation of project income to Project Adjusted EBITDA is included in the tables below.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

13. Segment and geographic information (Continued)

|  | Northeast |  | Southeast |  | Northwest |  | Southwest |  | Un-allocated Corporate |  | Consolidated |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Three months ended September 30, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Project revenues |  | $ | 47.3 |  | $ | 10.6 |  | $ | 23.5 |  | $ | 61.0 |  | $ | (0.6 | ) | $ | 141.8 |
Segment assets |  |  | 1,134.8 |  |  | 177.4 |  |  | 1,113.3 |  |  | 913.9 |  |  | 157.3 |  |  | 3,496.7 |
Project Adjusted EBITDA |  | $ | 24.9 |  | $ | 5.9 |  | $ | 19.4 |  | $ | 29.5 |  | $ | (3.5 | ) |  | 76.2 |
Change in fair value of derivative instruments |  |  | 3.5 |  |  | 0.5 |  |  | (0.5 | ) |  | — |  |  | — |  |  | 3.5 |
Depreciation and amortization |  |  | 17.8 |  |  | 3.4 |  |  | 15.1 |  |  | 14.9 |  |  | 0.2 |  |  | 51.4 |
Interest, net |  |  | 4.1 |  |  | 1.4 |  |  | 4.8 |  |  | 0.4 |  |  | (0.1 | ) |  | 10.6 |
Other project (income) expense |  |  | 31.4 |  |  | — |  |  | — |  |  | (26.3 | ) |  | 0.8 |  |  | 5.9 |
Project income (loss) |  |  | (31.9 | ) |  | 0.6 |  |  | (0.0 | ) |  | 40.5 |  |  | (4.4 | ) |  | 4.8 |
Administration |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 8.4 |  |  | 8.4 |
Interest, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 27.5 |  |  | 27.5 |
Foreign exchange gain |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 9.1 |  |  | 9.1 |
Other expense, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Income (loss) from continuing operations before income taxes |  |  | (31.9 | ) |  | 0.6 |  |  | (0.0 | ) |  | 40.5 |  |  | (49.4 | ) |  | (40.2 | )
Income tax expense |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Net income (loss) from continuing operations |  |  | (31.9 | ) |  | 0.6 |  |  | (0.0 | ) |  | 40.5 |  |  | (49.4 | ) |  | (40.2 | )
Income (loss) from discontinued operations |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.4 | ) |  | (0.4 | )
Net income (loss) |  | $ | (31.9 | ) | $ | 0.6 |  | $ | (0.0 | ) | $ | 40.5 |  | $ | (49.8 | ) | $ | (40.6 | )

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

13. Segment and geographic information (Continued)

|  | Northeast |  | Southeast |  | Northwest |  | Southwest |  | Un-allocated Corporate |  | Consolidated |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Three months ended September 30, 2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Project revenues |  | $ | 43.8 |  | $ | — |  | $ | 15.0 |  | $ | 47.7 |  | $ | (0.2 | ) | $ | 106.3 |
Segment assets |  |  | 1,157.9 |  |  | 446.3 |  |  | 852.0 |  |  | 1,162.6 |  |  | 25.2 |  |  | 3,644.0 |
Project Adjusted EBITDA |  | $ | 20.3 |  | $ | 2.3 |  | $ | 12.6 |  | $ | 23.4 |  | $ | (1.2 | ) |  | 57.4 |
Change in fair value of derivative instruments |  |  | (10.2 | ) |  | (0.6 | ) |  | — |  |  | — |  |  | — |  |  | (10.8 | )
Depreciation and amortization |  |  | 20.4 |  |  | 1.4 |  |  | 10.7 |  |  | 9.3 |  |  | — |  |  | 41.8 |
Interest, net |  |  | 4.5 |  |  | — |  |  | 1.2 |  |  | 0.1 |  |  | — |  |  | 5.8 |
Other project (income) expense |  |  | 0.3 |  |  | — |  |  | — |  |  | 0.2 |  |  | 0.4 |  |  | 0.9 |
Project income (loss) |  |  | 5.3 |  |  | 1.5 |  |  | 0.7 |  |  | 13.8 |  |  | (1.6 | ) |  | 19.7 |
Administration |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 6.3 |  |  | 6.3 |
Interest, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 25.8 |  |  | 25.8 |
Foreign exchange loss |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 7.7 |  |  | 7.7 |
Other expense, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.3 |  |  | 0.3 |
Income (loss) from continuing operations before income taxes |  |  | 5.3 |  |  | 1.5 |  |  | 0.7 |  |  | 13.8 |  |  | (41.7 | ) |  | (20.4 | )
Income tax expense |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 3.1 |  |  | 3.1 |
Net income (loss) from continuing operations |  |  | 5.3 |  |  | 1.5 |  |  | 0.7 |  |  | 13.8 |  |  | (44.8 | ) |  | (23.5 | )
Income (loss) from discontinued operations |  |  | — |  |  | 19.3 |  |  | — |  |  | 0.8 |  |  | (1.1 | ) |  | 19.0 |
Net income (loss) |  | $ | 5.3 |  | $ | 20.8 |  | $ | 0.7 |  | $ | 14.6 |  | $ | (45.9 | ) | $ | (4.5 | )

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

13. Segment and geographic information (Continued)

|  | Northeast |  | Southeast |  | Northwest |  | Southwest |  | Un-allocated Corporate |  | Consolidated |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Nine months ended September 30, 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Project revenues |  | $ | 167.9 |  | $ | 16.8 |  | $ | 69.5 |  | $ | 167.7 |  | $ | (0.9 | ) | $ | 421.0 |
Segment assets |  |  | 1,134.8 |  |  | 177.4 |  |  | 1,113.3 |  |  | 913.9 |  |  | 157.3 |  |  | 3,496.7 |
Project Adjusted EBITDA |  | $ | 96.8 |  | $ | 10.4 |  | $ | 53.0 |  | $ | 64.5 |  | $ | (11.4 | ) |  | 213.3 |
Change in fair value of derivative instruments |  |  | (12.9 | ) |  | (3.1 | ) |  | (18.8 | ) |  | — |  |  | — |  |  | (34.8 | )
Depreciation and amortization |  |  | 55.7 |  |  | 7.9 |  |  | 45.7 |  |  | 44.7 |  |  | 0.5 |  |  | 154.5 |
Interest, net |  |  | 12.8 |  |  | 2.6 |  |  | 14.2 |  |  | 0.9 |  |  | — |  |  | 30.5 |
Other project (income) expense |  |  | 32.3 |  |  | 0.1 |  |  | — |  |  | (26.6 | ) |  | — |  |  | 5.8 |
Project income (loss) |  |  | 8.9 |  |  | 2.9 |  |  | 11.9 |  |  | 45.5 |  |  | (11.9 | ) |  | 57.3 |
Administration |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 28.5 |  |  | 28.5 |
Interest, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 78.7 |  |  | 78.7 |
Foreign exchange gain |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (12.9 | ) |  | (12.9 | )
Other expense, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (9.5 | ) |  | (9.5 | )
Income (loss) from continuing operations before income taxes |  |  | 8.9 |  |  | 2.9 |  |  | 11.9 |  |  | 45.5 |  |  | (96.7 | ) |  | (27.5 | )
Income tax benefit |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1.9 | ) |  | (1.9 | )
Net income (loss) from continuing operations |  |  | 8.9 |  |  | 2.9 |  |  | 11.9 |  |  | 45.5 |  |  | (94.8 | ) |  | (25.6 | )
Income (loss) from discontinued operations |  |  | — |  |  | (1.1 | ) |  | — |  |  | 1.3 |  |  | (6.3 | ) |  | (6.1 | )
Net income (loss) |  | $ | 8.9 |  | $ | 1.8 |  | $ | 11.9 |  | $ | 46.8 |  | $ | (101.1 | ) | $ | (31.7 | )

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

13. Segment and geographic information (Continued)

|  | Northeast |  | Southeast |  | Northwest |  | Southwest |  | Un-allocated Corporate |  | Consolidated |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Nine months ended September 30, 2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Project revenues |  | $ | 156.6 |  | $ | — |  | $ | 46.9 |  | $ | 121.7 |  | $ | 1.2 |  | $ | 326.4 |
Segment assets |  |  | 1,157.9 |  |  | 446.3 |  |  | 852.0 |  |  | 1,162.6 |  |  | 25.2 |  |  | 3,644.0 |
Project Adjusted EBITDA |  | $ | 85.2 |  | $ | 6.5 |  | $ | 38.5 |  | $ | 48.0 |  | $ | (7.5 | ) |  | 170.7 |
Change in fair value of derivative instruments |  |  | 46.3 |  |  | 2.6 |  |  | — |  |  | — |  |  | — |  |  | 48.9 |
Depreciation and amortization |  |  | 58.0 |  |  | 4.3 |  |  | 31.7 |  |  | 28.9 |  |  | 0.1 |  |  | 123.0 |
Interest, net |  |  | 13.9 |  |  | — |  |  | 3.8 |  |  | 0.4 |  |  | — |  |  | 18.1 |
Other project (income) expense |  |  | 0.8 |  |  | — |  |  | — |  |  | 2.9 |  |  | 0.7 |  |  | 4.4 |
Project income (loss) |  |  | (33.8 | ) |  | (0.4 | ) |  | 3.0 |  |  | 15.8 |  |  | (8.3 | ) |  | (23.7 | )
Administration |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 22.0 |  |  | 22.0 |
Interest, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 69.3 |  |  | 69.3 |
Foreign exchange loss |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4.4 |  |  | 4.4 |
Other expense, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (5.7 | ) |  | (5.7 | )
Income (loss) from continuing operations before income taxes |  |  | (33.8 | ) |  | (0.4 | ) |  | 3.0 |  |  | 15.8 |  |  | (98.3 | ) |  | (113.7 | )
Income tax expense |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (19.1 | ) |  | (19.1 | )
Net income (loss) from continuing operations |  |  | (33.8 | ) |  | (0.4 | ) |  | 3.0 |  |  | 15.8 |  |  | (79.2 | ) |  | (94.6 | )
Income (loss) from discontinued operations |  |  | — |  |  | 49.5 |  |  | — |  |  | 1.5 |  |  | (2.2 | ) |  | 48.8 |
Net income (loss) |  | $ | (33.8 | ) | $ | 49.1 |  | $ | 3.0 |  | $ | 17.3 |  | $ | (81.4 | ) | $ | (45.8 | )

The tables below provide information, by country, about our consolidated operations. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.

|  |  |  |  |  |  |  |  |  | Property, Plant and Equipment, net of accumulated depreciation |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
|  | Project Revenue Three months ended September 30, |  | Project Revenue Nine months ended September 30, |
|  | September 30, 2013 |  | December 31, 2012 |
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
United States |  | $ | 98.0 |  | $ | 61.0 |  | $ | 264.7 |  | $ | 171.9 |  | $ | 1,368.0 |  | $ | 1,504.8 |
Canada |  |  | 43.8 |  |  | 45.3 |  |  | 156.3 |  |  | 154.5 |  |  | 505.9 |  |  | 550.7 |
Total |  | $ | 141.8 |  | $ | 106.3 |  | $ | 421.0 |  | $ | 326.4 |  | $ | 1,873.9 |  | $ | 2,055.5 |

The Ontario Electricity Financial Corp ("OEFC"), British Columbia Hydro and Power Authority ("BC Hydro"), San Diego Gas & Electric ("SD G&E") provided for approximately 20.7%, 10.2%, and 13.1% respectively, of total consolidated revenues for the three months ended September 30, 2013 and 26.3%, 10.8%, and 10.2% respectively, of total consolidated revenues for the nine months ended

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

13. Segment and geographic information (Continued)

September 30, 2013. OEFC and BC Hydro provided for approximately 18.7% and 9.2%, respectively, of total consolidated revenues for the three months ended September 30, 2012 and 22.1% and 9.7% respectively, of total consolidated revenues for the nine months ended September 30, 2012. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the Northeast segment, BC Hydro purchases electricity from the Mamquam, Moresby Lake and Williams Lake projects in the Northwest segment, and SD G&E purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the Southwest segment.

14. Commitments and contingencies

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

Shareholder class action lawsuits

Massachusetts District Court Actions

On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against Atlantic Power and Barry E. Welch, our President and Chief Executive Officer and a Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the "Individual Defendants," and together with Atlantic Power, the "Defendants") (the "U.S. Actions").

The District Court complaints differ in terms of the identities of the Individual Defendants they name, as noted above, the named plaintiffs, and the purported class period they allege (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleges, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The District Court complaints assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.

The parties to each District Court action have filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the "Amended Complaint"), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing

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14. Commitments and contingencies (Continued)

regarding any such motion to dismiss); and (iii) confirming that Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the "U.S. Lead Plaintiff Applicants") filed a motion (collectively, the "U.S. Lead Plaintiff Motions") with the District Court seeking: (i) to consolidate the five U.S. Actions (the "Consolidated U.S. Action"); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013, which the Court will consider (along with the motion papers discussed above) in deciding who will serve as lead plaintiff and lead counsel.

Canadian Actions

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

On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario.

On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. This claim names the Company, Barry Welch and Terrence Ronan as defendants (the "Defendants"). The Plaintiffs seeks leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserts common law claims for misrepresentation. The Plaintiffs' allegations focus on among other things, claims the Defendants made materially false and misleading statements and omissions in Atlantic Power's press releases, quarterly and year end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The Plaintiffs seek to certify the statutory and common law claims under the Class Proceedings Act for security holders who purchased and held securities through a proposed class period of November 5, 2012 to February 28, 2013.

On October 4, 2013 the Plaintiffs delivered materials supporting their request for leave to commence an action for statutory misrepresentations and for certification of the statutory and common claims as class proceedings. These materials estimate the damages claimed for statutory misrepresentation at $197.4 million.

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A schedule for the Plaintiffs' motions and the action will be set on November 12, 2013.

The Petitioner in the proposed Quebec class action has served and filed a motion to suspend those proceedings until a decision is made on certification of the Ontario action as a class proceeding. This motion will not be contested.

Pursuant to the Private Securities Litigation Reform Act of 1995, all discovery is stayed in the U.S. Actions. Plaintiffs have not yet specified an amount of alleged damages in the U.S. Actions. As noted above, the plaintiffs in the Canadian Action have estimated their alleged statutory damages at $197.4 million. Because both the U.S. and Canadian Actions are in their early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation. Atlantic Power intends to defend vigorously each of the actions.

Other

Other than as described above, there were no material changes to legal proceedings disclosed in "Item 3. Legal Proceedings" of our Annual Report on Form 10-K for the year ended December 31, 2012.

In addition to the matters listed, 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. With respect to such other matters arising in the normal course of business, there are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of September 30, 2013.

15. Guarantees and condensed consolidating financial information

In connection with the tax equity investments in our Canadian Hills project, we have expressly indemnified the investors for certain representations and warranties made by a wholly-owned subsidiary with respect to matters which we believe are remote and improbable to occur. The expiration dates of these guarantees vary from less than one year through the indefinite termination date of the project. Our maximum undiscounted potential exposure is limited to the amount of tax equity investment less cash distributions made to the investors and any amount equal to the net federal income tax benefits arising from production tax credits.

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 certain tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.

As of September 30, 2013 and December 31, 2012, we had $460.0 million of Senior Notes. These notes are guaranteed by certain of our wholly owned subsidiaries, or guarantor subsidiaries. These guarantees are joint and several.

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Unless otherwise noted below, each of the following 100% owned guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2013:

Atlantic Power Limited Partnership, Atlantic Power GP Inc., Atlantic Power (US) GP, Atlantic Oklahoma Wind LLC, Atlantic Power Corporation, Atlantic Power Generation, Inc., Atlantic Power Transmission, Inc., Atlantic Power Holdings, Inc.,. Atlantic Power Services Canada GP Inc., Atlantic Power Services Canada LP, Atlantic Power Services, LLC, Atlantic Rockland Holdings, LLC, Teton Power Funding, LLC, Harbor Capital Holdings, LLC, Epsilon Power Funding, LLC, Atlantic Cadillac Holdings, LLC, Atlantic Idaho Wind Holdings, LLC, Atlantic Idaho Wind C, LLC, Baker Lake Hydro, LLC, Olympia Hydro, LLC, Teton East Coast Generation, LLC, Atlantic Renewables Holdings, LLC, Orlando Power Generation I, LLC, Orlando Power Generation II, LLC, Atlantic Piedmont Holdings LLC, Teton Selkirk, LLC, Teton Operating Services, LLC, Atlantic Ridgeline Holdings, LLC, Ridgeline Energy Holdings, Inc., Ridgeline Energy LLC, Pah Rah Holding Company LLC, Lewis Ranch Wind Project LLC, Hurricane Wind LLC, Ridgeline Power Services LLC, Ridgeline Eastern Energy LLC, Ridgeline Alternative Energy LLC, Frontier Solar LLC, Ridgeline Energy Solar LLC, Pah Rah Project Company LLC, Monticello Hills Wind LLC, Dry Lots Wind LLC, Smokey Avenue Wind LLC, Saunders Bros. Transportation Corporation, Bruce Hill Wind LLC, South Mountain Wind LLC, Great Basin Solar Ranch LLC, Goshen Wind Holdings LLC, Meadow Creek Holdings LLC, Ridgeline Holdings Junior Inc., Rockland Wind Ridgeline Holdings LLC and Meadow Creek Intermediate Holdings LLC.

The following condensed consolidating financial information presents the financial information of Atlantic Power, the guarantor subsidiaries, and Curtis Palmer, LLC ("Curtis Palmer") (our non-guarantor subsidiary) in accordance with Rule 3-10 under the SEC's Regulation S-X. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or Curtis Palmer operated as independent entities.

In this presentation, Atlantic Power consists of parent company operations. Guarantor subsidiaries of Atlantic Power are reported on a combined basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

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ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2013
(in millions of U.S. dollars)
(Unaudited)

|  | Guarantor Subsidiaries |  | Curtis Palmer |  | Atlantic Power |  | Eliminations |  | Consolidated Balance |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 163.5 |  | $ | — |  | $ | 7.2 |  | $ | — |  | $ | 170.7 |
Restricted cash |  |  | 119.8 |  |  | — |  |  | — |  |  | — |  |  | 119.8 |
Accounts receivable |  |  | 165.9 |  |  | 10.9 |  |  | 2.8 |  |  | (116.3 | ) |  | 63.3 |
Prepayments, supplies, and other current assets |  |  | 32.2 |  |  | 2.3 |  |  | 0.8 |  |  | (1.0 | ) |  | 34.3 |
Total current assets |  |  | 481.4 |  |  | 13.2 |  |  | 10.8 |  |  | (117.3 | ) |  | 388.1 |
Property, plant, and equipment, net |  |  | 1,702.7 |  |  | 172.5 |  |  | — |  |  | (1.3 | ) |  | 1,873.9 |
Equity investments in unconsolidated affiliates |  |  | 3,753.9 |  |  | — |  |  | 963.7 |  |  | (4,313.1 | ) |  | 404.5 |
Other intangible assets, net |  |  | 321.5 |  |  | 149.6 |  |  | — |  |  | — |  |  | 471.1 |
Goodwill |  |  | 238.1 |  |  | 58.2 |  |  | — |  |  | — |  |  | 296.3 |
Other assets |  |  | 473.7 |  |  | — |  |  | 434.3 |  |  | (845.2 | ) |  | 62.8 |
Total assets |  | $ | 6,971.3 |  | $ | 393.5 |  | $ | 1,408.8 |  | $ | (5,276.9 | ) | $ | 3,496.7 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | $ | 118.6 |  | $ | 3.9 |  | $ | 83.9 |  | $ | (116.3 | ) | $ | 90.1 |
Revolving credit facility |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Current portion of long-term debt |  |  | 16.7 |  |  | 190.0 |  |  | — |  |  | — |  |  | 206.7 |
Other current liabilities |  |  | 40.0 |  |  | — |  |  | 3.9 |  |  | (1.0 | ) |  | 42.9 |
Total current liabilities |  |  | 175.3 |  |  | 193.9 |  |  | 87.8 |  |  | (117.3 | ) |  | 339.7 |
Long-term debt |  |  | 814.1 |  |  | — |  |  | 460.0 |  |  | — |  |  | 1,274.1 |
Convertible debentures |  |  | — |  |  | — |  |  | 414.1 |  |  | — |  |  | 414.1 |
Other non-current liabilities |  |  | 1,184.0 |  |  | 8.5 |  |  | 0.5 |  |  | (845.2 | ) |  | 347.8 |
Total liabilities |  |  | 2,173.4 |  |  | 202.4 |  |  | 962.4 |  |  | (962.5 | ) |  | 2,375.7 |
Equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Preferred shares issued by a subsidiary company |  |  | 232.1 |  |  | — |  |  | — |  |  | (10.8 | ) |  | 221.3 |
Common shares |  |  | 4,323.5 |  |  | 191.1 |  |  | 1,285.8 |  |  | (4,514.7 | ) |  | 1,285.7 |
Accumulated other comprehensive loss |  |  | (8.7 | ) |  | — |  |  | — |  |  | — |  |  | (8.7 | )
Retained deficit |  |  | (21.3 | ) |  | — |  |  | (839.4 | ) |  | 211.1 |  |  | (649.6 | )
Total Atlantic Power Corporation shareholders' equity |  |  | 4,525.6 |  |  | 191.1 |  |  | 446.4 |  |  | (4,314.4 | ) |  | 848.7 |
Noncontrolling interest |  |  | 272.3 |  |  | — |  |  | — |  |  | — |  |  | 272.3 |
Total equity |  |  | 4,797.9 |  |  | 191.1 |  |  | 446.4 |  |  | (4,314.4 | ) |  | 1,121.0 |
Total liabilities and equity |  | $ | 6,971.3 |  | $ | 393.5 |  | $ | 1,408.8 |  | $ | (5,276.9 | ) | $ | 3,496.7 |

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ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Three months ended September 30, 2013
(in millions of U.S. dollars)

|  | Guarantor Subsidiaries |  | Curtis Palmer |  | Atlantic Power |  | Eliminations |  | Consolidated Balance |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total project revenue |  | $ | 134.2 |  | $ | 7.8 |  | $ | — |  | $ | (0.2 | ) | $ | 141.8 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 47.2 |  |  | — |  |  | — |  |  | — |  |  | 47.2 |
Project operations and maintenance |  |  | 36.8 |  |  | 1.3 |  |  | — |  |  | (0.1 | ) |  | 38.0 |
Development |  |  | 1.4 |  |  | — |  |  | — |  |  | — |  |  | 1.4 |
Depreciation and amortization |  |  | 38.4 |  |  | 3.8 |  |  | — |  |  | — |  |  | 42.2 |
|  |  | 123.8 |  |  | 5.1 |  |  | — |  |  | (0.1 | ) |  | 128.8 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | (3.5 | ) |  | — |  |  | — |  |  | — |  |  | (3.5 | )
Equity in earnings of unconsolidated affiliates |  |  | 39.1 |  |  | — |  |  | — |  |  | — |  |  | 39.1 |
Interest expense, net |  |  | (6.3 | ) |  | (2.7 | ) |  | — |  |  | — |  |  | (9.0 | )
Other |  |  | (34.8 | ) |  | — |  |  | — |  |  | — |  |  | (34.8 | )
|  |  | (5.5 | ) |  | (2.7 | ) |  | — |  |  | — |  |  | (8.2 | )
Project income |  |  | 4.9 |  |  | — |  |  | — |  |  | (0.1 | ) |  | 4.8 |
Administrative and other expenses (income): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Administration expense |  |  | 4.9 |  |  | — |  |  | 3.5 |  |  | — |  |  | 8.4 |
Interest, net |  |  | 18.9 |  |  | — |  |  | 8.6 |  |  | — |  |  | 27.5 |
Foreign exchange loss |  |  | 4.1 |  |  | — |  |  | 5.0 |  |  | — |  |  | 9.1 |
Other income |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
|  |  | 27.9 |  |  | — |  |  | 17.1 |  |  | — |  |  | 45.0 |
Loss from continuing operations before income taxes |  |  | (23.0 | ) |  | — |  |  | (17.1 | ) |  | (0.1 | ) |  | (40.2 | )
Income tax benefit |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Net loss from continuing operations |  |  | (23.0 | ) |  | — |  |  | (17.1 | ) |  | (0.1 | ) |  | (40.2 | )
Net loss from discontinued operations |  |  | (0.4 | ) |  | — |  |  | — |  |  | — |  |  | (0.4 | )
Net loss |  |  | (23.4 | ) |  | — |  |  | (17.1 | ) |  | (0.1 | ) |  | (40.6 | )
Net income (loss) attributable to noncontrolling interest |  |  | (2.5 | ) |  | — |  |  | — |  |  | 3.2 |  |  | 0.7 |
Net loss attributable to Atlantic Power Corporation |  | $ | (20.9 | ) | $ | — |  | $ | (17.1 | ) | $ | (3.3 | ) | $ | (41.3 | )

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ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Nine months ended September 30, 2013
(in millions of U.S. dollars)

|  | Guarantor Subsidiaries |  | Curtis Palmer |  | Atlantic Power |  | Eliminations |  | Consolidated Balance |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total project revenue |  | $ | 394.1 |  | $ | 27.4 |  | $ | — |  | $ | (0.5 | ) | $ | 421.0 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 148.8 |  |  | — |  |  | — |  |  | — |  |  | 148.8 |
Project operations and maintenance |  |  | 110.0 |  |  | 2.2 |  |  | 0.5 |  |  | (0.4 | ) |  | 112.3 |
Development |  |  | 4.9 |  |  | — |  |  | — |  |  | — |  |  | 4.9 |
Depreciation and amortization |  |  | 114.2 |  |  | 11.5 |  |  | — |  |  | — |  |  | 125.7 |
|  |  | 377.9 |  |  | 13.7 |  |  | 0.5 |  |  | (0.4 | ) |  | 391.7 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | 33.4 |  |  | — |  |  | — |  |  | — |  |  | 33.4 |
Equity in earnings of unconsolidated affiliates |  |  | 55.0 |  |  | — |  |  | — |  |  | — |  |  | 55.0 |
Interest expense, net |  |  | (17.4 | ) |  | (8.3 | ) |  | — |  |  | — |  |  | (25.7 | )
Other |  |  | (35.0 | ) |  | — |  |  | 0.3 |  |  | — |  |  | (34.7 | )
|  |  | 36.0 |  |  | (8.3 | ) |  | 0.3 |  |  | — |  |  | 28.0 |
Project income |  |  | 52.2 |  |  | 5.4 |  |  | (0.2 | ) |  | (0.1 | ) |  | 57.3 |
Administrative and other expenses (income): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Administration expense |  |  | 15.3 |  |  | — |  |  | 13.2 |  |  | — |  |  | 28.5 |
Interest, net |  |  | 57.1 |  |  | — |  |  | 21.6 |  |  | — |  |  | 78.7 |
Foreign exchange loss |  |  | (3.9 | ) |  | — |  |  | (9.0 | ) |  | — |  |  | (12.9 | )
Other income |  |  | (9.5 | ) |  | — |  |  | — |  |  |  |  |  | (9.5 | )
|  |  | 59.0 |  |  | — |  |  | 25.8 |  |  | — |  |  | 84.8 |
Income (loss) from continuing operations before income taxes |  |  | (6.8 | ) |  | 5.4 |  |  | (26.0 | ) |  | (0.1 | ) |  | (27.5 | )
Income tax benefit |  |  | (1.9 | ) |  | — |  |  | — |  |  | — |  |  | (1.9 | )
Net income (loss) from continuing operations |  |  | (4.9 | ) |  | 5.4 |  |  | (26.0 | ) |  | (0.1 | ) |  | (25.6 | )
Net loss from discontinued operations |  |  | (6.1 | ) |  | — |  |  | — |  |  | — |  |  | (6.1 | )
Net income (loss) |  |  | (11.0 | ) |  | 5.4 |  |  | (26.0 | ) |  | (0.1 | ) |  | (31.7 | )
Net income (loss) attributable to noncontrolling interest |  |  | (3.3 | ) |  | — |  |  | — |  |  | 9.5 |  |  | 6.2 |
Net income (loss) attributable to Atlantic Power Corporation |  | $ | (7.7 | ) | $ | 5.4 |  | $ | (26.0 | ) | $ | (9.6 | ) | $ | (37.9 | )

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ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME
Three and nine months ended September 30, 2013
(in millions of U.S. dollars)

|  | Guarantor Subsidiaries |  | Curtis Palmer |  | Atlantic Power |  | Eliminations |  | Consolidated Balance |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Net loss |  | $ | (23.4 | ) | $ | — |  | $ | (17.1 | ) | $ | (0.1 | ) | $ | (40.6 | )
Other comprehensive income (loss): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unrealized gain on hedging activities |  |  | (0.1 | ) |  | — |  |  | — |  |  | — |  |  | (0.1 | )
Net amount reclassified to earnings |  |  | 0.2 |  |  | — |  |  | — |  |  | — |  |  | 0.2 |
Net unrealized losses on derivatives |  |  | 0.1 |  |  | — |  |  | — |  |  | — |  |  | 0.1 |
Foreign currency translation adjustments |  |  | 10.7 |  |  | — |  |  | — |  |  | — |  |  | 10.7 |
Other comprehensive income, net of tax |  |  | 10.8 |  |  | — |  |  | — |  |  | — |  |  | 10.8 |
Comprehensive loss |  |  | (12.6 | ) |  | — |  |  | (17.1 | ) |  | (0.1 | ) |  | (29.8 | )
Less: Comprehensive income attributable to noncontrolling interest |  |  | 0.7 |  |  | — |  |  | — |  |  | — |  |  | 0.7 |
Comprehensive loss attributable to Atlantic Power Corporation |  | $ | (13.3 | ) | $ | — |  | $ | (17.1 | ) | $ | (0.1 | ) | $ | (30.5 | )

|  | Guarantor Subsidiaries |  | Curtis Palmer |  | Atlantic Power |  | Eliminations |  | Consolidated Balance |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Net income (loss) |  | $ | (11.0 | ) | $ | 5.4 |  | $ | (26.0 | ) | $ | (0.1 | ) | $ | (31.7 | )
Other comprehensive income (loss): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unrealized gain on hedging activities |  |  | 0.5 |  |  | — |  |  | — |  |  | — |  |  | 0.5 |
Net amount reclassified to earnings |  |  | 0.6 |  |  | — |  |  | — |  |  | — |  |  | 0.6 |
Net unrealized losses on derivatives |  |  | 1.1 |  |  | — |  |  | — |  |  | — |  |  | 1.1 |
Foreign currency translation adjustments |  |  | (19.3 | ) |  | — |  |  | — |  |  | — |  |  | (19.3 | )
Other comprehensive income, net of tax |  |  | (18.2 | ) |  | — |  |  | — |  |  | — |  |  | (18.2 | )
Comprehensive income (loss) |  |  | (29.2 | ) |  | 5.4 |  |  | (26.0 | ) |  | (0.1 | ) |  | (49.9 | )
Less: Comprehensive income attributable to noncontrolling interest |  |  | 6.2 |  |  | — |  |  | — |  |  | — |  |  | 6.2 |
Comprehensive income (loss) attributable to Atlantic Power Corporation |  | $ | (35.4 | ) | $ | 5.4 |  | $ | (26.0 | ) | $ | (0.1 | ) | $ | (56.1 | )

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

15. Guarantees and condensed consolidating financial information (Continued)

ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Nine months ended September 30, 2013
(in millions of U.S. dollars)

|  | Guarantor Subsidiaries |  | Curtis Palmer |  | Atlantic Power |  | Eliminations |  | Consolidated Balance |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Net cash provided by operating activities |  | $ | 69.8 |  | $ | 2.4 |  | $ | 71.1 |  | $ | — |  | $ | 143.3 |
Cash flows provided by (used in) investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from treasury grant |  |  | 103.2 |  |  | — |  |  | — |  |  | — |  |  | 103.2 |
Proceeds for sale of assets |  |  | 183.0 |  |  | — |  |  | — |  |  | — |  |  | 183.0 |
Cash (paid) received for equity investments |  |  | 8.5 |  |  | — |  |  | (8.5 | ) |  | — |  |  | — |
Change in restricted cash |  |  | (99.1 | ) |  | — |  |  | — |  |  | — |  |  | (99.1 | )
Biomass development costs |  |  | (0.1 | ) |  | — |  |  | — |  |  | — |  |  | (0.1 | )
Construction in progress |  |  | (32.2 | ) |  | — |  |  | — |  |  | — |  |  | (32.2 | )
Purchase of property, plant and equipment |  |  | (4.8 | ) |  | (2.4 | ) |  | — |  |  | — |  |  | (7.2 | )
Net cash provided by (used in) investing activities |  |  | 158.5 |  |  | (2.4 | ) |  | (8.5 | ) |  | — |  |  | 147.6 |
Cash flows provided by (used in) financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Offering costs related to tax equity |  |  | (1.0 | ) |  | — |  |  | — |  |  | — |  |  | (1.0 | )
Repayment of project-level debt |  |  | (115.3 | ) |  | — |  |  | — |  |  | — |  |  | (115.3 | )
Proceeds from project-level debt |  |  | 20.8 |  |  | — |  |  | — |  |  | — |  |  | 20.8 |
Payments for revolving credit facility borrowings |  |  | (47.0 | ) |  | — |  |  | (20.0 | ) |  | — |  |  | (67.0 | )
Equity investment from noncontrolling interest |  |  | 42.6 |  |  | — |  |  | 1.9 |  |  | — |  |  | 44.5 |
Deferred financing costs |  |  | (0.5 | ) |  | — |  |  | — |  |  | — |  |  | (0.5 | )
Dividends paid |  |  | (13.9 | ) |  | — |  |  | (54.2 | ) |  | — |  |  | (68.1 | )
Net cash used in financing activities |  |  | (114.3 | ) |  | — |  |  | (72.3 | ) |  | — |  |  | (186.6 | )
Net increase (decrease) in cash and cash equivalents |  |  | 114.0 |  |  | — |  |  | (9.7 | ) |  | — |  |  | 104.3 |
Cash and cash equivalents at beginning of period |  |  | 49.5 |  |  | — |  |  | 16.9 |  |  | — |  |  | 66.4 |
Cash and cash equivalents at end of period |  | $ | 163.5 |  | $ | — |  | $ | 7.2 |  | $ | — |  | $ | 170.7 |

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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 amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due;
•
  the amount of cash proceeds expected to be received following the sale of our projects and the timing of such sales;
•
  our ability to meet the financial covenants under our senior credit facility and other indebtedness and the ability to maintain our dividend payments at the current level;
•
  our potential requirement to provide additional security to a natural gas supplier's agreements and the expected amount of such security; 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 this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2012. Our business is both highly competitive and subject to various risks.

These risks include, without limitation:

•
  the outcome of certain shareholder class action lawsuits;
•
  the impact on us of recent amendments to and compliance with our senior credit facility;
•
  the impact of compliance with covenants under our 9% senior unsecured notes;
•
  changes in our creditworthiness;
•
  the expiration or termination of power purchase agreements;
•
  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;
•
  projects not operating according to plan;
•
  the dependence of our projects on third-party suppliers;

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•
  the effects of weather, which affects demand for electricity and fuel as well as operating conditions;
•
  the dependence of our windpower projects on suitable wind and associated conditions;
•
  U.S., Canadian and/or global economic conditions and uncertainty;
•
  risks beyond our control, including but not limited to acts of terrorism or related acts of war, geopolitical crisis, natural disasters or other catastrophic events;
•
  the adequacy of our insurance coverage;
•
  the impact of significant energy, environmental and other regulations on our projects;
•
  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;
•
  construction risks;
•
  labor disruptions;
•
  our ability to retain, motivate and recruit executives and other key employees;
•
  unstable capital and credit markets; and
•
  our indebtedness and financing arrangements.

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 or cash flows 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 this Quarterly Report on Form 10-Q and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

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

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

OVERVIEW

Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of September 30, 2013, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 3,018 megawatts ("MW") in which our aggregate ownership interest is approximately 2,098 MW. These totals exclude our 40% interest in the Delta-Person generating station ("Delta-Person") for which we entered into an agreement to sell in December 2012. Our current portfolio consists of interests in twenty-nine operational power generation projects across eleven states in the United States and two provinces in Canada. We also own Ridgeline Energy Holdings, Inc. ("Ridgeline"), a wind and solar developer in Seattle, and we own a majority interest in Rollcast Energy Inc. ("Rollcast"), a biomass power plant developer in North Carolina for which we have initiated a plan to sell our interest. Twenty-three of our projects are wholly owned subsidiaries.

We sell 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 August 2014 to December 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 majority of our natural gas 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 more than half of our power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects, including Colorado Energy Management ("CEM"), Power Plant Management Services ("PPMS") and Delta Power Services ("DPS"). Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

RECENT DEVELOPMENTS

Goodwill Impairment

During the second quarter of 2013, based on a prolonged decline in our market capitalization we determined that it was appropriate to initiate a test of goodwill to determine if the fair value of each of our reporting units' goodwill does not exceed their carrying amounts. We concluded the test during the three months ended September 30, 2013 and determined that goodwill was impaired at the Kenilworth,

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Naval Station, Naval Training Center and North Island ("Naval reporting units") reporting units. The total non-cash impairment charge recorded was $34.9 million.

The $30.8 million impairment at Kenilworth was due to lower forecasted capacity and energy prices compared to the assumptions at the time of the acquisition in November 2011. When performing our step 2 quantitative analysis, the increase in the intangible value associated with the new Energy Service Agreement ("ESA") entered into in July 2013 resulted in a lower implied goodwill value. At the time of its acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Kenilworth project were valued assuming a merchant basis for the period subsequent to the expiration of the project's original PPA in July 2012. As discussed above, these forecasted energy revenues on a merchant basis were higher than the current forecasted energy prices subsequent to the expiration of the new ESA. The $4.1 million impairment at the Naval reporting units was primarily due to increased uncertainty, not assumed at the time of the reporting units acquisition in 2011, in our ability to extend two of the projects lease and steam agreements upon their expiration. In addition, lower currently forecasted capacity and energy prices in California after the expiration of the PPAs compared to the forecast at the time of the acquisition in 2011 result in a lower business enterprise value which resulted in a lower implied goodwill value.

During the three months ended June 30, 2013, we recorded a $3.5 million impairment of goodwill at Rollcast which is a component of our Un-allocated corporate segment. We determined, based on the results of the two-step process, that the carrying amount of goodwill exceeded the implied fair value of goodwill. We also wrote-off $1.4 million of capitalized development costs at Rollcast related to the Greenway development project. The determination to impair goodwill and write-off the capitalized development costs was based on the reduced expectation of the Greenway project being further developed.

Rollcast

During the three months ended September 30, 2013, we initiated and approved a plan to sell our 60% interest in our Rollcast projects and classified our Rollcast investment, which is a component of the un-allocated corporate segment, as a held for sale business based on our plan to sell the project within the next twelve months. Accordingly, the assets and liabilities of Rollcast have been presented separately as held for sale in the consolidated balance sheet at September 30, 2013 and the project's net loss is recorded as loss from discontinued operations in the consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012.

Amendment to the Senior Credit Facility

On August 2, 2013, we entered into an amendment to the senior credit facility with our lenders primarily to obtain more favorable financial covenant ratios. The amendment includes changes to our borrowing capacity, financial ratios and certain other customary representations, warranties, terms and conditions and covenants. For a description of these changes, see "—Liquidity and Capital Resources" and Note 5 to the consolidated financial statements included in this Quarterly Report on Form 10-Q.

Administration and Development Reductions

In July 2013, we implemented changes in several areas that are expected to result in an approximate $8.0 million reduction to administration and development expenses relative to our previous 2014 budget for those items. The expected expense reductions are targeted to occur in three broad areas, which are, in order of significance: (1) reduction in the development budget, both for personnel and third-party expenses, consistent with de-emphasizing early-stage development projects; (2) consolidation of accounting and finance functions in two offices, down from three; and

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(3) additional synergies from full integration of areas such as health care, plant insurance, IT, travel and other functions.

Most of the one-time costs incurred to implement these changes were recorded in the third quarter of 2013 with the remainder to be recorded in the fourth quarter of 2013. The savings are expected to be realized beginning in 2014. However, we may experience increases in unrelated costs such as those associated with our debt reduction objectives and plant optimization initiatives. The net impact on cash flows is expected to be positive in 2014.

Piedmont Commercial Operations and Receipt of Grant Proceeds

In May 2013, Piedmont submitted an application under the federal 1603 grant program. In July, the grant was approved and $49.5 million was received from the U.S. Treasury. With the proceeds received and a $1.5 million contribution from Atlantic Power to cover the shortfall created by the U.S. federal budget sequestration, the project's outstanding $51.0 million bridge loan was fully repaid in July 2013. Piedmont's construction loan ($76.6 million at September 30, 2013) is expected to convert to a term loan in the fourth quarter of 2013. We contributed an additional $2.7 million equity investment during the three months ended June 30, 2013 to fund the project's working capital.

Piedmont achieved commercial operation under its PPA with Georgia Power Company at a declared capacity of 53.5 MW on April 19, 2013. Piedmont and its engineering, procurement and construction ("EPC") contractor, Zachry Industrial, Inc. ("Zachry"), are disputing certain issues under the EPC agreement regarding the condition and performance of the project, during which time Piedmont is withholding the amount still retained under the agreement.

Canadian Hills Tax Equity

On May 2, 2013, we syndicated our $44.0 million tax equity investment in Canadian Hills to an institutional investor and received cash proceeds of $42.1 million. The cash proceeds received were based on our initial tax equity investment of $44.1 million less distributions received from Canadian Hills resulting in an immaterial loss on the sale. During this short-term ownership as a tax equity investor in the project, we generated an immaterial amount of production tax credits and approximately $5.5 million of net operating losses, which we will be able to use to offset against future taxable income. The syndication of our interest completes the sale of 100% of Canadian Hills' $269 million of tax equity interests. The cash proceeds will be held for general corporate purposes. We continue to own 99% of the project and consolidate it in our consolidated financial statements. Income, (losses), and distributions attributable to the tax investors are recorded as a component of noncontrolling interests.

Sale of Gregory

On April 2, 2013 we and the other owners of Gregory entered into a purchase and sale agreement with an affiliate of NRG Energy, Inc. to sell the project for approximately $274.2 million including working capital adjustments. We received net cash proceeds from our ownership interest of approximately $34.7 million in the aggregate, after repayment of project-level debt and transaction expenses. Approximately $5.0 million of these proceeds will be held in escrow for up to one year after the closing date. We intend to use the net proceeds from the sale for general corporate purposes. The sale of Gregory closed on August 7, 2013 resulting in a gain of $30.4 million and was recorded in equity in earnings of unconsolidated affiliates in the consolidated statement of operations for the three and nine months ended September 30, 2013.

Sale of Path 15

On March 11, 2013 we entered into a purchase and sale agreement with Duke-American Transmission Company, a joint venture between Duke Energy Corporation and American

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Transmission Co., to sell our interests in Path 15. The sale closed on April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of approximately $52 million, plus a management agreement termination fee of $4.0 million, for a total sale price of approximately $56 million. The cash proceeds will be used for general corporate purposes. All project level debt issued by Path 15, totaling $137.2 million, transferred with the sale. Path 15 was accounted for as an asset held for sale in the consolidated balance sheets at December 31, 2012 and as a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012.

Sale of Florida Projects

On January 30, 2013, we entered into a purchase and sale agreement for the sale of the Florida Projects, for approximately $140 million, with working capital adjustments. The sale closed on April 12, 2013 and we received net cash proceeds of approximately $117 million in the aggregate, after repayment of project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale. This includes approximately $92 million received at closing and cash distributions from the projects of approximately $25 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully repay our senior credit facility, which had an outstanding balance of approximately $64.1 million on the closing date. The Florida Projects were accounted for as assets held for sale in the consolidated balance sheets at December 31, 2012 and are a component of discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2013 and the three and nine months ended September 30, 2012.

OUR POWER PROJECTS

The table on the following page outlines our portfolio of power generating assets in operation as of November 7, 2013, 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"). Customers that have assigned ratings at the top end of the range have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate the customers, and/or maintain their current ratings. A security rating is not a recommendation to buy, sell or hold securities, it 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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Project |  | Location |  | Type |  | MW |  | Economic Interest |  | Net MW |  | Primary Electric Purchasers |  | Power Contract Expiry |  | Customer Credit Rating (S&P)
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Northeast Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cadillac |  | Michigan |  | Biomass |  |  | 40 |  |  | 100.00 | % |  | 40 |  | Consumers Energy |  |  | December 2028 |  | BBB
Chambers |  | New Jersey |  | Coal |  |  | 262 |  |  | 40.00 | % |  | 89 |  | Atlantic City Elec. |  |  | December 2024 |  | BBB+
|  |  |  |  |  |  |  |  |  |  |  |  | 16 |  | DuPont |  |  | December 2024 |  | A
Kenilworth |  | New Jersey |  | Natural Gas |  |  | 30 |  |  | 100.00 | % |  | 30 |  | Merck, & Co., Inc. |  |  | September 2018(1) |  | AA
Curtis Palmer |  | New York |  | Hydro |  |  | 60 |  |  | 100.00 | % |  | 60 |  | Niagara Mohawk Power Corperation |  |  | December 2027 |  | A-
Selkirk |  | New York |  | Natural Gas |  |  | 345 |  |  | 18.50 | % |  | 15 |  | Merchant |  |  | N/A |  | N/R
|  |  |  |  |  |  |  |  |  |  |  |  | 49 |  | Consolidated Edison |  |  | August 2014 |  | A-
Calstock |  | Ontario |  | Biomass |  |  | 35 |  |  | 100.00 | % |  | 35 |  | Ontario Electricity Financial Corp |  |  | June 2020 |  | AA-
Kapuskasing |  | Ontario |  | Natural Gas |  |  | 40 |  |  | 100.00 | % |  | 40 |  | Ontario Electricity Financial Corp |  |  | December 2017 |  | AA-
Nipigon |  | Ontario |  | Natural Gas |  |  | 40 |  |  | 100.00 | % |  | 40 |  | Ontario Electricity Financial Corp |  |  | December 2022 |  | AA-
North Bay |  | Ontario |  | Natural Gas |  |  | 40 |  |  | 100.00 | % |  | 40 |  | Ontario Electricity Financial Corp |  |  | December 2017 |  | AA-
Tunis |  | Ontario |  | Natural Gas |  |  | 43 |  |  | 100.00 | % |  | 43 |  | Ontario Electricity Financial Corp |  |  | December 2014 |  | AA-
Southeast Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Orlando |  | Florida |  | Natural Gas |  |  | 129 |  |  | 50.00 | % |  | 46 |  | Progress Energy Florida |  |  | December 2023 |  | BBB+
|  |  |  |  |  |  |  |  |  |  |  |  | 19 |  | Reedy Creek Improvement District(2) |  |  | December 2013 |  | A
Piedmont |  | Georgia |  | Biomass |  |  | 53 |  |  | 98.0 | % |  | 52 |  | Georgia Power |  |  | December 2032 |  | A
Northwest Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mamquam |  | British Columbia |  | Hydro |  |  | 50 |  |  | 100.00 | % |  | 50 |  | British Columbia Hydro and Power Authority |  |  | September 2027 |  | AAA
Moresby Lake |  | British Columbia |  | Hydro |  |  | 6 |  |  | 100.00 | % |  | 6 |  | British Columbia Hydro and Power Authority |  |  | August 2022 |  | AAA
Williams Lake |  | British Columbia |  | Biomass |  |  | 66 |  |  | 100.00 | % |  | 66 |  | British Columbia Hydro and Power Authority |  |  | March 2018 |  | AAA
Idaho Wind |  | Idaho |  | Wind |  |  | 183 |  |  | 27.56 | % |  | 50 |  | Idaho Power Co. |  |  | December 2030 |  | BBB
Rockland |  | Idaho |  | Wind |  |  | 80 |  |  | 50.00 | % |  | 40 |  | Idaho Power Co. |  |  | December 2036 |  | BBB
Goshen North |  | Idaho |  | Wind |  |  | 125 |  |  | 12.50 | % |  | 16 |  | Southern California Edison |  |  | November 2030 |  | BBB+
Meadow Creek |  | Idaho |  | Wind |  |  | 120 |  |  | 100.00 | % |  | 120 |  | PacifiCorp |  |  | December 2032 |  | A-
Frederickson |  | Washington |  | Natural Gas |  |  | 250 |  |  | 50.15 | % |  | 50 |  | Benton Co. PUD |  |  | August 2022 |  | A+
|  |  |  |  |  |  |  |  |  |  |  |  | 45 |  | Grays Harbor PUD |  |  | August 2022 |  | A
|  |  |  |  |  |  |  |  |  |  |  |  | 30 |  | Franklin, Co. PUD |  |  | August 2022 |  | A
Koma Kulshan |  | Washington |  | Hydro |  |  | 13 |  |  | 49.80 | % |  | 6 |  | Puget Sound Energy |  |  | December 2037 |  | BBB
Southwest Segment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Naval Station |  | California |  | Natural Gas |  |  | 47 |  |  | 100.00 | % |  | 47 |  | San Diego Gas & Electric |  |  | December 2019 |  | A
Naval Training Center |  | California |  | Natural Gas |  |  | 25 |  |  | 100.00 | % |  | 25 |  | San Diego Gas & Electric |  |  | December 2019 |  | A
North Island(3) |  | California |  | Natural Gas |  |  | 40 |  |  | 100.00 | % |  | 40 |  | San Diego Gas & Electric |  |  | December 2019 |  | A
Oxnard |  | California |  | Natural Gas |  |  | 49 |  |  | 100.00 | % |  | 49 |  | Southern California Edison |  |  | May 2020 |  | BBB+
Greeley |  | Colorado |  | Natural Gas |  |  | 72 |  |  | 100 | % |  | 72 |  | Public Service Company of Colorado |  |  | August 2013(4) |  | A-
Manchief |  | Colorado |  | Natural Gas |  |  | 300 |  |  | 100 | % |  | 300 |  | Public Service Company of Colorado |  |  | October 2022 |  | A-
Morris |  | Illinois |  | Natural Gas |  |  | 177 |  |  | 100 | % |  | 77 |  | Merchant |  |  | N/A |  | N/R
|  |  |  |  |  |  |  |  |  |  |  |  | 100 |  | Equistar Chemicals, LP |  |  | November 2023 |  | BBB
Canadian Hills |  | Oklahoma |  | Wind |  |  | 298 |  |  | 99.0 | % |  | 199 |  | Southwestern Electric Power Company |  |  | December 2037 |  | BBB
|  |  |  |  |  |  |  |  |  |  |  |  | 48 |  | Oklahoma Municipal Power Authority |  |  | December 2037 |  | A
|  |  |  |  |  |  |  |  |  |  |  |  | 48 |  | Grand River Dam Authority |  |  | December 2032 |  | A

(1)
  The Kenilworth ESA, under which Kenilworth sells electricity and steam to Merck expired on July 31, 2012 and was extended on a month-to month basis by agreement with the purchaser. In July 2013, we entered into a new ESA with Merck that became effective November 1, 2013 and expires on September 30, 2018.
(2)
  Upon the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to Progress Energy Florida under the terms of the current agreement.
(3)
  North Island received approval in August 2013 to increase its interconnection capacity from 38 MW to 42 MW. PPA capacity will remain unchanged and the additional 4 MW can be sold at the short run avoided cost energy price.
(4)
  The Greeley project's PPA expired in August 2013. The project is currently being decommissioned.

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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 nine months ended September 30, 2013 and 2012 which are analyzed in greater detail below:

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Project income (loss) |  | $ | 4.8 |  | $ | 19.7 |  | $ | 57.3 |  | $ | (23.7 | )
Loss from continuing operations |  |  | (40.2 | ) |  | (23.5 | ) |  | (25.6 | ) |  | (94.6 | )
Income (loss) from discontinued operations, net of tax |  |  | (0.4 | ) |  | 19.0 |  |  | (6.1 | ) |  | 48.8 |
Net loss attributable to Atlantic Power Corporation |  |  | (41.3 | ) |  | (7.5 | ) |  | (37.9 | ) |  | (54.9 | )
Basic and diluted loss per share from continuing operations |  | $ | (0.34 | ) | $ | (0.22 | ) | $ | (0.27 | ) | $ | (0.90 | )
Project Adjusted EBITDA(1) |  |  | 76.2 |  |  | 57.4 |  |  | 213.3 |  |  | 170.7 |
Cash Available for Distribution(1) |  |  | 37.9 |  |  | 28.3 |  |  | 109.9 |  |  | 101.0 |

(1)
  See reconciliation and definition in Supplementary Non-GAAP Financial Information.

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Three months ended September 30, 2013 compared to the three months ended September 30, 2012

The following table provides our consolidated results of operations:

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | $ change |  | % change |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 73.4 |  | $ | 49.6 |  |  | 23.8 |  |  | 48.0 | %
Energy capacity revenue |  |  | 51.1 |  |  | 42.8 |  |  | 8.3 |  |  | 19.4 |
Other |  |  | 17.3 |  |  | 13.9 |  |  | 3.4 |  |  | 24.5 | %
|  |  | 141.8 |  |  | 106.3 |  |  | 35.5 |  |  | 33.4 | %
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 47.2 |  |  | 40.1 |  |  | 7.1 |  |  | 17.7 | %
Operations and maintenance |  |  | 38.0 |  |  | 26.5 |  |  | 11.5 |  |  | 43.4 | %
Development |  |  | 1.4 |  |  | — |  |  | 1.4 |  |  | NM |
Depreciation and amortization |  |  | 42.2 |  |  | 30.6 |  |  | 11.6 |  |  | 37.9 | %
|  |  | 128.8 |  |  | 97.2 |  |  | 31.6 |  |  | 32.5 | %
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | (3.5 | ) |  | 10.7 |  |  | (14.2 | ) |  | NM |
Equity in earnings of unconsolidated affiliates |  |  | 39.1 |  |  | 4.0 |  |  | 35.1 |  |  | NM |
Interest expense, net |  |  | (9.0 | ) |  | (4.1 | ) |  | (4.9 | ) |  | NM |
Impairment of goodwill |  |  | (34.9 | ) |  | — |  |  | (34.9 | ) |  | NM |
Other, net |  |  | 0.1 |  |  | — |  |  | 0.1 |  |  | NM |
|  |  | (8.2 | ) |  | 10.6 |  |  | (18.8 | ) |  | NM |
Project income |  |  | 4.8 |  |  | 19.7 |  |  | (14.9 | ) |  | NM |
Administrative and other expenses (income): |  |  |  |  |  |  |  |  |  |  |  |  |
Administration |  |  | 8.4 |  |  | 6.3 |  |  | 2.1 |  |  | 33.3 | %
Interest, net |  |  | 27.5 |  |  | 25.8 |  |  | 1.7 |  |  | 6.6 | %
Foreign exchange loss |  |  | 9.1 |  |  | 7.7 |  |  | 1.4 |  |  | 18.2 | %
Other expense, net |  |  | — |  |  | 0.3 |  |  | (0.3 | ) |  | NM |
|  |  | 45.0 |  |  | 40.1 |  |  | 4.9 |  |  | 12.2 | %
Loss from continuing operations before income taxes |  |  | (40.2 | ) |  | (20.4 | ) |  | (19.8 | ) |  | -97.1 | %
Income tax expense |  |  | — |  |  | 3.1 |  |  | (3.1 | ) |  | NM |
Loss from continuing operations |  |  | (40.2 | ) |  | (23.5 | ) |  | (16.7 | ) |  | -71.1 | %
Income (loss) from discontinued operations, net of tax |  |  | (0.4 | ) |  | 19.0 |  |  | (19.4 | ) |  | NM |
Net loss |  |  | (40.6 | ) |  | (4.5 | ) |  | (36.1 | ) |  | NM |
Net loss attributable to noncontrolling interests |  |  | (2.5 | ) |  | (0.4 | ) |  | (2.1 | ) |  | NM |
Net income attributable to preferred shares dividends of a subsidiary company |  |  | 3.2 |  |  | 3.4 |  |  | (0.2 | ) |  | -5.9 | %
Net loss attributable to Atlantic Power Corporation |  | $ | (41.3 | ) | $ | (7.5 | ) |  | (33.8 | ) |  | NM |

Project Income (loss) by Segment

We have five reportable segments: Northeast, Southeast, Northwest, Southwest and Un-allocated Corporate. The segment classified as Un-allocated Corporate includes activities that support the executive offices, capital structure, costs of being a public registrant in the United States and Canada, costs to develop future projects and intercompany eliminations. Unallocated Corporate also includes Rollcast, a 60% owned company, which develops, owns and operates renewable power plants that use

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wood or biomass fuel, and for which we have initiated a plan to sell, and Ridgeline, which develops and operates wind and solar renewable projects. 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. A significant non-cash item that impacts project income (loss) and is subject to potentially significant fluctuations is the change in fair value of certain derivative financial instruments. These instruments are required by GAAP to be revalued at each balance sheet date (see Item 3. "Quantitative and Qualitative Disclosures About Market Risk" for additional information).

|  | Three months ended September 30, 2013 |
--- | --- | --- | ---
|  | Northeast |  | Southeast(1) |  | Northwest |  | Southwest(2) |  | Un-allocated Corporate(3) |  | Consolidated Total |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 26.6 |  | $ | 3.2 |  | $ | 17.9 |  | $ | 26.3 |  | $ | (0.6 | ) | $ | 73.4 |
Energy capacity revenue |  |  | 18.9 |  |  | 7.3 |  |  | — |  |  | 24.8 |  |  | 0.1 |  |  | 51.1 |
Other |  |  | 1.8 |  |  | 0.1 |  |  | 5.6 |  |  | 9.9 |  |  | (0.1 | ) |  | 17.3 |
|  |  | 47.3 |  |  | 10.6 |  |  | 23.5 |  |  | 61.0 |  |  | (0.6 | ) |  | 141.8 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 20.7 |  |  | 3.6 |  |  | 1.5 |  |  | 21.4 |  |  | — |  |  | 47.2 |
Operations and maintenance |  |  | 12.6 |  |  | 3.4 |  |  | 8.1 |  |  | 11.7 |  |  | 2.2 |  |  | 38.0 |
Development |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1.4 |  |  | 1.4 |
Depreciation and amortization |  |  | 15.0 |  |  | 1.9 |  |  | 10.9 |  |  | 14.3 |  |  | 0.1 |  |  | 42.2 |
|  |  | 48.3 |  |  | 8.9 |  |  | 20.5 |  |  | 47.4 |  |  | 3.7 |  |  | 128.8 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | (3.4 | ) |  | (0.5 | ) |  | 0.5 |  |  | — |  |  | (0.1 | ) |  | (3.5 | )
Equity in earnings of unconsolidated affiliates |  |  | 7.2 |  |  | 0.8 |  |  | — |  |  | 31.3 |  |  | (0.2 | ) |  | 39.1 |
Interest expense, net |  |  | (3.9 | ) |  | (1.4 | ) |  | (3.5 | ) |  | (0.3 | ) |  | 0.1 |  |  | (9.0 | )
Impairment of goodwill |  |  | (30.8 | ) |  | — |  |  | — |  |  | (4.1 | ) |  | — |  |  | (34.9 | )
Other, net |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.1 |  |  | 0.1 |
|  |  | (30.9 | ) |  | (1.1 | ) |  | (3.0 | ) |  | 26.9 |  |  | (0.1 | ) |  | (8.2 | )
Project income (loss) |  | $ | (31.9 | ) | $ | 0.6 |  | $ | — |  | $ | 40.5 |  | $ | (4.4 | ) | $ | 4.8 |

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|  | Three months ended September 30, 2012 |
--- | --- | --- | ---
|  | Northeast |  | Southeast(1) |  | Northwest |  | Southwest(2) |  | Un-allocated Corporate(3) |  | Consolidated Total |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 24.6 |  | $ | — |  | $ | 9.9 |  | $ | 15.2 |  | $ | (0.1 | ) | $ | 49.6 |
Energy capacity revenue |  |  | 17.6 |  |  | — |  |  | — |  |  | 25.2 |  |  | — |  |  | 42.8 |
Other |  |  | 1.6 |  |  | — |  |  | 5.1 |  |  | 7.3 |  |  | (0.1 | ) |  | 13.9 |
|  |  | 43.8 |  |  | — |  |  | 15.0 |  |  | 47.7 |  |  | (0.2 | ) |  | 106.3 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 23.2 |  |  | — |  |  | 1.0 |  |  | 16.0 |  |  | (0.1 | ) |  | 40.1 |
Operations and maintenance |  |  | 9.3 |  |  | 0.1 |  |  | 5.7 |  |  | 10.0 |  |  | 1.4 |  |  | 26.5 |
Development |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Depreciation and amortization |  |  | 15.4 |  |  | — |  |  | 6.5 |  |  | 8.5 |  |  | 0.2 |  |  | 30.6 |
|  |  | 47.9 |  |  | 0.1 |  |  | 13.2 |  |  | 34.5 |  |  | 1.5 |  |  | 97.2 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | 10.4 |  |  | (0.2 | ) |  | — |  |  | — |  |  | 0.5 |  |  | 10.7 |
Equity in earnings of unconsolidated affiliates |  |  | 3.4 |  |  | 1.8 |  |  | (1.1 | ) |  | 0.6 |  |  | (0.7 | ) |  | 4.0 |
Interest expense, net |  |  | (4.3 | ) |  | — |  |  | — |  |  | — |  |  | 0.2 |  |  | (4.1 | )
Other, net |  |  | (0.1 | ) |  | — |  |  | — |  |  | — |  |  | 0.1 |  |  | — |
|  |  | 9.4 |  |  | 1.6 |  |  | (1.1 | ) |  | 0.6 |  |  | 0.1 |  |  | 10.6 |
Project income (loss) |  | $ | 5.3 |  | $ | 1.5 |  | $ | 0.7 |  | $ | 13.8 |  | $ | (1.6 | ) | $ | 19.7 |

(1)
  Excludes the Florida Projects which are designated as discontinued operations.
(2)
  Excludes Path 15 which is designated as discontinued operations.
(3)
  Excludes Rollcast which is designated as discontinued operations.

Northeast

Project income for the three months ended September 30, 2013 decreased $37.2 million from the comparable 2012 period primarily due to:

•
  decreased project income from Kenilworth of $29.9 million due primarily to a $30.8 million non-cash goodwill impairment charge recorded in the third quarter of 2013; and
•
  decreased project income from Nipigon of $12.2 million due primarily to an $8.8 million non-cash decrease in the fair value of a gas purchase agreement that is accounted for as a derivative instrument and increased maintenance costs of $3.0 million resulting from a scheduled outage.

This decrease was partially offset by:

•
  increased project income from Curtis Palmer of $3.6 million attributable to increased generation resulting from higher water levels than the comparable period; and
•
  increased project income from Selkirk of $3.8 million due primarily to lower fuel cost and operations and maintenance expense than the comparable period.

Southeast

Project income for the three months ended September 30, 2013 did not change materially from the comparable 2012 period. Project income for the Southeast segment excludes the Florida Projects which

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are accounted for as a component of discontinued operations and were sold on April 12, 2013. Project income for the Florida Projects was $19.3 million for the three months ended September 30, 2012.

Northwest

Project income for the three months ended September 30, 2013 did not change materially from the comparable 2012 period.

Southwest

Project income for the three months ended September 30, 2013 increased $26.7 million from the comparable 2012 period.

The net change for the period results primarily from:

•
  increased project income of $30.7 million at Gregory primarily due to a $30.4 million gain on sale resulting from the project being sold in August 2013; and
•
  increased project income from Morris of $1.7 million primarily attributable to lower fuel costs and higher revenues than the comparable period as well as total increased project income of $0.8 million across the remaining Southwest projects.

This increase was partially offset by:

•
  decreased project income of $3.5 million at Naval Station, Naval Training Center, and North Island due primarily to a $4.1 million non-cash goodwill impairment charge recorded in the third quarter of 2013; and
•
  a $2.5 million project loss at Canadian Hills, due primarily to lower than expected wind generation and $6.0 million of depreciation and amortization. The Canadian Hills project did not become operational until the fourth quarter of 2012.

Project income for the Southwest segment excludes the Path 15 project which was sold on April 30, 2013 and which is accounted for as a component of discontinued operations. Project income for Path 15 was $1.4 million for the three months ended September 30, 2012.

Un-allocated Corporate

Total project loss increased $2.8 million for the three months ended September 30, 2013 from the comparable 2012 period primarily due to $1.4 million of development expense at Ridgeline which was acquired in December 2012.

Administrative and other expenses (income)

Administrative and other expenses (income) include the income and expenses not attributable to our projects and are allocated to the Un-allocated Corporate segment. These costs include the activities that support the executive offices, capital structure, costs of being a public registrant in the United States and Canada, costs to develop future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate tax. Significant non-cash items that impact Administrative and other expenses (income), which are subject to potentially significant fluctuations, include the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar-denominated obligations and the related deferred income tax expense (benefit) associated with these non-cash items.

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Administration

Administration expense for the three months ended September 30, 2013 increased $2.1 million or 33.3% from the comparable 2012 period primarily due to professional fees incurred related to the amendment of the senior credit facility and the shareholder class action lawsuits.

Interest, net

Interest, net for the three months ended September 30, 2013 increased $1.7 million or 6.6% from the comparable 2012 period primarily due to issuance of the Cdn$100 million principal amount of convertible debentures in December of 2012.

Foreign exchange loss

Foreign exchange loss increased $1.4 million or 18.2% primarily due to a $4.5 million decrease in unrealized gain of foreign currency forward contracts and a $1.0 million decrease in realized gains on the settlement of foreign currency forward contracts, offset by a $4.1 million decrease in losses from the revaluation of instruments denominated in Canadian dollars. The U.S. dollar to Canadian dollar exchange rate was 1.0303 at September 30, 2013 and decreased by 2.0% in three months ended September 30, 2013 as compared to a 3.4% decrease in the comparable 2012 period.

Other income, net

Other income, net did not change materially for the three months ended September 30, 2013 from the comparable 2012 period.

Income tax expense (benefit)

There was no income tax expense recorded for the three months ended September 30, 2013. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 25%, was $10.0 million. The primary items impacting the tax rate for the three months ended September 30, 2013 were $13.7 million relating to goodwill impairment, $3.6 million relating to foreign exchange, $3.7 million relating to dividend withholding tax and $5.1 million of other permanent differences. These items were partially offset by $8.2 million relating to a change in the valuation allowance and $9.1 million relating to 1603 Treasury grant proceeds received.

Income tax expense for the three months ended September 30, 2012 was $3.1 million. The difference between the actual tax benefit and the expected income tax benefit, based on the Canadian enacted statutory rate of 25%, of $5.1 million for the three months ended September 30, 2012 is primarily due to due to foreign currency translation difference in tax rates in other countries, change in valuation allowance and various other permanent differences.

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Nine months ended September 30, 2013 compared to the nine months ended September 30, 2012

The following table provides our consolidated results of operations:

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | $ change |  | % change |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 228.6 |  | $ | 159.0 |  |  | 69.6 |  |  | 43.8 | %
Energy capacity revenue |  |  | 132.2 |  |  | 117.3 |  |  | 14.9 |  |  | 12.7 | %
Other |  |  | 60.2 |  |  | 50.1 |  |  | 10.1 |  |  | 20.2 | %
|  |  | 421.0 |  |  | 326.4 |  |  | 94.6 |  |  | 29.0 | %
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 148.8 |  |  | 123.6 |  |  | 25.2 |  |  | 20.4 | %
Operations and maintenance |  |  | 112.3 |  |  | 88.0 |  |  | 24.3 |  |  | 27.6 | %
Development |  |  | 4.9 |  |  | — |  |  | 4.9 |  |  | NM |
Depreciation and amortization |  |  | 125.7 |  |  | 87.3 |  |  | 38.4 |  |  | 44.0 | %
|  |  | 391.7 |  |  | 298.9 |  |  | 92.8 |  |  | 31.0 | %
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | 33.4 |  |  | (51.3 | ) |  | 84.7 |  |  | NM |
Equity in earnings of unconsolidated affiliates |  |  | 55.0 |  |  | 12.4 |  |  | 42.6 |  |  | NM |
Interest expense, net |  |  | (25.7 | ) |  | (12.3 | ) |  | (13.4 | ) |  | 108.9 | %
Impairment of goodwill |  |  | (34.9 | ) |  | — |  |  | (34.9 | ) |  | NM |
Other, net |  |  | 0.2 |  |  | — |  |  | 0.2 |  |  | NM |
|  |  | 28.0 |  |  | (51.2 | ) |  | 79.2 |  |  | NM |
Project income (loss) |  |  | 57.3 |  |  | (23.7 | ) |  | 81.0 |  |  | NM |
Administrative and other expenses (income): |  |  |  |  |  |  |  |  |  |  |  |  |
Administration |  |  | 28.5 |  |  | 22.0 |  |  | 6.5 |  |  | 29.5 | %
Interest, net |  |  | 78.7 |  |  | 69.3 |  |  | 9.4 |  |  | 13.6 | %
Foreign exchange (gain) loss |  |  | (12.9 | ) |  | 4.4 |  |  | (17.3 | ) |  | NM |
Other income, net |  |  | (9.5 | ) |  | (5.7 | ) |  | (3.8 | ) |  | 66.7 | %
|  |  | 84.8 |  |  | 90.0 |  |  | (5.2 | ) |  | -5.8 | %
Loss from continuing operations before income taxes |  |  | (27.5 | ) |  | (113.7 | ) |  | 86.2 |  |  | 75.8 | %
Income tax benefit |  |  | (1.9 | ) |  | (19.1 | ) |  | 17.2 |  |  | NM |
Loss from continuing operations |  |  | (25.6 | ) |  | (94.6 | ) |  | 69.0 |  |  | 72.9 | %
Income (loss) from discontinued operations, net of tax |  |  | (6.1 | ) |  | 48.8 |  |  | (54.9 | ) |  | -112.5 | %
Net loss |  |  | (31.7 | ) |  | (45.8 | ) |  | 14.1 |  |  | 30.8 | %
Net income (loss) |  |  | (31.7 | ) |  | (45.8 | ) |  | 14.1 |  |  | 30.8 | %
Net loss attributable to noncontrolling interests |  |  | (3.3 | ) |  | (0.7 | ) |  | (2.6 | ) |  | NM |
Net income attributable to preferred shares dividends of a subsidiary company |  |  | 9.5 |  |  | 9.8 |  |  | (0.3 | ) |  | -3.1 | %
Net loss attributable to Atlantic Power Corporation |  | $ | (37.9 | ) | $ | (54.9 | ) |  | 17.0 |  |  | 31.0 | %

Project Income (loss) by Segment

We have five reportable segments: Northeast, Southeast, Northwest, Southwest and Un-allocated Corporate. The segment classified as Un-allocated Corporate includes activities that support the executive offices, capital structure, costs of being a public registrant in the United States and Canada, costs to develop future projects and intercompany eliminations. Un-allocated Corporate also includes

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Rollcast, a 60% owned company, which develops, owns and operates renewable power plants that use wood or biomass fuel and Ridgeline, which develops and operates wind and solar renewable projects. 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. A significant non-cash item that impacts project income (loss) and is subject to potentially significant fluctuations is the change in fair value of certain derivative financial instruments. These instruments are required by GAAP to be revalued at each balance sheet date (see Item 3. "Quantitative and Qualitative Disclosures About Market Risk" for additional information).

|  | Nine months ended September 30, 2013 |
--- | --- | --- | ---
|  | Northeast |  | Southeast(1) |  | Northwest |  | Southwest(2) |  | Un-allocated Corporate(3) |  | Consolidated Total |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 92.1 |  | $ | 5.3 |  | $ | 52.0 |  | $ | 79.5 |  | $ | (0.3 | ) | $ | 228.6 |
Energy capacity revenue |  |  | 62.7 |  |  | 11.3 |  |  | — |  |  | 58.2 |  |  | — |  |  | 132.2 |
Other |  |  | 13.1 |  |  | 0.2 |  |  | 17.5 |  |  | 30.0 |  |  | (0.6 | ) |  | 60.2 |
|  |  | 167.9 |  |  | 16.8 |  |  | 69.5 |  |  | 167.7 |  |  | (0.9 | ) |  | 421.0 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 69.7 |  |  | 6.5 |  |  | 6.0 |  |  | 66.6 |  |  | — |  |  | 148.8 |
Operations and maintenance |  |  | 32.6 |  |  | 6.6 |  |  | 27.5 |  |  | 40.2 |  |  | 5.4 |  |  | 112.3 |
Development |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4.9 |  |  | 4.9 |
Depreciation and amortization |  |  | 45.3 |  |  | 3.5 |  |  | 33.5 |  |  | 42.9 |  |  | 0.5 |  |  | 125.7 |
|  |  | 147.6 |  |  | 16.6 |  |  | 67.0 |  |  | 149.7 |  |  | 10.8 |  |  | 391.7 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | 12.9 |  |  | 3.1 |  |  | 17.4 |  |  | — |  |  | — |  |  | 33.4 |
Equity in earnings of unconsolidated affiliates |  |  | 18.4 |  |  | 2.2 |  |  | 2.5 |  |  | 32.0 |  |  | (0.1 | ) |  | 55.0 |
Interest expense, net |  |  | (11.9 | ) |  | (2.6 | ) |  | (10.5 | ) |  | (0.7 | ) |  | — |  |  | (25.7 | )
Impairment of goodwill |  |  | (30.8 | ) |  | — |  |  | — |  |  | (4.1 | ) |  | — |  |  | (34.9 | )
Other, net |  |  | — |  |  | — |  |  | — |  |  | 0.3 |  |  | (0.1 | ) |  | 0.2 |
|  |  | (11.4 | ) |  | 2.7 |  |  | 9.4 |  |  | 27.5 |  |  | (0.2 | ) |  | 28.0 |
Project income (loss) |  | $ | 8.9 |  | $ | 2.9 |  | $ | 11.9 |  | $ | 45.5 |  | $ | (11.9 | ) | $ | 57.3 |

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|  | Nine months ended September 30, 2012 |
--- | --- | --- | ---
|  | Northeast |  | Southeast(1) |  | Northwest |  | Southwest(2) |  | Un-allocated Corporate(3) |  | Consolidated Total |
Project revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy sales |  | $ | 89.4 |  | $ | — |  | $ | 30.3 |  | $ | 39.2 |  | $ | 0.1 |  | $ | 159.0 |
Energy capacity revenue |  |  | 57.1 |  |  | — |  |  | — |  |  | 60.2 |  |  | — |  |  | 117.3 |
Other |  |  | 10.1 |  |  | — |  |  | 16.6 |  |  | 22.3 |  |  | 1.1 |  |  | 50.1 |
|  |  | 156.6 |  |  | — |  |  | 46.9 |  |  | 121.7 |  |  | 1.2 |  |  | 326.4 |
Project expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  | 72.3 |  |  | — |  |  | 5.8 |  |  | 45.4 |  |  | 0.1 |  |  | 123.6 |
Operations and maintenance |  |  | 30.3 |  |  | 0.1 |  |  | 17.9 |  |  | 30.5 |  |  | 9.2 |  |  | 88.0 |
Development |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Depreciation and amortization |  |  | 42.8 |  |  | — |  |  | 19.6 |  |  | 24.9 |  |  | — |  |  | 87.3 |
|  |  | 145.4 |  |  | 0.1 |  |  | 43.3 |  |  | 100.8 |  |  | 9.3 |  |  | 298.9 |
Project other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of derivative instruments |  |  | (48.8 | ) |  | (2.5 | ) |  | — |  |  | — |  |  | — |  |  | (51.3 | )
Equity in earnings of unconsolidated affiliates |  |  | 15.9 |  |  | 2.3 |  |  | (0.7 | ) |  | (5.1 | ) |  | — |  |  | 12.4 |
Interest expense, net |  |  | (12.2 | ) |  | — |  |  | — |  |  | — |  |  | (0.1 | ) |  | (12.3 | )
Other, net |  |  | 0.1 |  |  | (0.1 | ) |  | 0.1 |  |  | — |  |  | (0.1 | ) |  | — |
|  |  | (45.0 | ) |  | (0.3 | ) |  | (0.6 | ) |  | (5.1 | ) |  | (0.2 | ) |  | (51.2 | )
Project income (loss) |  | $ | (33.8 | ) | $ | (0.4 | ) | $ | 3.0 |  | $ | 15.8 |  | $ | (8.3 | ) | $ | (23.7 | )

(1)
  Excludes the Florida Projects which are designated as discontinued operations.
(2)
  Excludes Path 15 which is designated as discontinued operations.
(3)
  Excludes Rollcast which is designated as discontinued operations.

Northeast

Project income for the nine months ended September 30, 2013 increased $42.7 million from the comparable 2012 period primarily due to:

•
  increased project income from North Bay of $29.7 million due primarily to a positive $29.9 million non-cash change in the fair value of gas purchase agreements that were accounted for as derivatives;
•
  increased project income from Kapuskasing of $29.3 million due primarily to a positive $29.9 million non-cash change in the fair value of gas purchase agreements that were accounted for as derivatives;
•
  increased project income from Curtis Palmer of $6.3 million due primarily to increased generation resulting from higher water levels than the comparable period;
•
  increased project income from Selkirk of $5.6 million due primarily to increased generation resulting in higher revenues and lower maintenance costs than the comparable period; and
•
  increased project income from Calstock of $5.0 million due primarily to a steam turbine maintenance in 2012 that contributed to increased generation, lower maintenance costs, and lower fuel costs than in the comparable period.

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These increases were partially offset by:

•
  decreased project income from Kenilworth of $27.5 million due primarily to a $30.8 million non-cash goodwill impairment charge recorded in the third quarter of 2013; and
•
  decreased project income from Tunis of $3.4 million due primarily to lower generation and energy prices.

Southeast

Project income for the nine months ended September 30, 2013 increased $3.3 million from the comparable 2012 period primarily due to revenue from the Piedmont project which became commercially operational in April 2013. Piedmont's $2.0 million of project income was also due to a positive $6.6 million non-cash change in the fair value of interest rate swap agreements that were accounted for as derivatives. This gain was offset by increased maintenance and interest expenses.

Project income for the Southeast segment excludes the Florida Projects which are accounted for as a component of discontinued operations and were sold on April 12, 2013. Project income for the Florida Projects was immaterial for the nine months ended September 30, 2013 and was $49.5 million for the nine months ended September 30, 2012.

Northwest

Project income for the nine months ended September 30, 2013 increased $8.9 million from the comparable 2012 period primarily due to:

•
  increased project income from Rockland of $7.9 million attributable to the 100% consolidation of a former equity method project subsequent to an ownership change from 30% to 50% as part of the Ridgeline acquisition during the fourth quarter of 2012; and
•
  increased project income from Meadow Creek of $3.7 million which achieved commercial operations in December 2012. Meadow Creek's project income was primarily due to a positive $9.0 million non-cash change in the fair value of interest rate swap agreements that were accounted for as derivatives. The gain was offset by $6.2 million of interest expense.

These increases were partially offset by:

•
  decreased project income from Mamquam of $4.2 million primarily attributable to increased maintenance costs from a scheduled outage and lower revenues due to lower water flows than the comparable period.

Southwest

Project income for the nine months ended September 30, 2013 increased $29.7 million from the comparable 2012 period primarily due to:

•
  increased project income from Gregory of $32.9 million primarily due to a $30.4 million gain on sale resulting from the project being sold in August 2013; and
•
  the sale of the Badger Creek project which was sold in August in 2012 and had a $2.8 million project loss recorded in the comparable period.

These increases were partially offset by:

•
  decreased project income of $5.3 million at Naval Station, Naval Training Center, and North Island due primarily to a $4.1 million non-cash goodwill impairment charge recorded in the third quarter of 2013; and

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•
  decreased project income from Morris of $3.4 million due to higher maintenance costs from a scheduled outage, higher fuel expenses, and lower revenues in the comparable period.

Project income for the Southwest segment excludes the Path 15 project, which was sold on April 30, 2013 and which is accounted for as a component of discontinued operations. Project income for Path 15 was $2.1 million and $2.7 million for the nine months ended September 30, 2013 and 2012, respectively and did not change materially.

Un-allocated Corporate

Project loss increased $3.6 million for the nine months ended September 30, 2013 from the comparable 2012 period primarily due to $4.9 million of development expense at Ridgeline which was acquired in December 2012.

Administrative and other expenses (income)

Administrative and other expenses (income) include the income and expenses not attributable to our projects and are allocated to the Un-allocated Corporate segment. These costs include the activities that support the executive offices, capital structure, costs of being a public registrant in the United States and Canada, costs to develop future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate tax. Significant non-cash items that impact Administrative and other expenses (income), which are subject to potentially significant fluctuations, include the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar-denominated obligations and the related deferred income tax expense (benefit) associated with these non-cash items.

Administration

Administration expense for the nine months ended September 30, 2013 increased $6.5 million or 29.5% from the comparable 2012 period primarily due to transactional fees during the nine months ended September 30, 2013 related to divestitures as well as professional fees incurred related to the amendment of the senior credit facility and the shareholder class action lawsuits.

Interest, net

Interest, net for the nine months ended September 30, 2013 increased $9.4 million or 13.7% from the comparable 2012 period primarily due to the issuance of the $130 million principal amount of convertible debentures in July of 2012 and issuance of the Cdn$100 million principal amount of convertible debentures in December of 2012.

Foreign exchange (gain) loss

Foreign exchange gain for the nine months ended September 30, 2013 increased $17.3 million primarily due to a $30.4 million increase in unrealized gain in the revaluation of instruments denominated in Canadian dollars offset by a $10.4 million increase in unrealized loss on foreign exchange forward contracts and a $2.7 million decrease in realized gains on the settlement of foreign currency forward contracts. The U.S. dollar to Canadian dollar exchange rate was 1.0303 at September 30, 2013 and increased by 3.6% in the nine months ended September 30, 2013 compared to a 3.3% decrease in the comparable 2012 period.

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Other income, net

Other income, net for the nine months ended September 30, 2013 increased $3.8 million or 66.7% from the comparable 2012 period primarily due to a $10.3 million gain on sale and management agreement termination fee resulting from the sale of Path 15. In the comparable 2012 period, we recorded a $6.0 million management agreement termination fee related to the sale of our equity interest in PERH.

Income tax expense (benefit)

Income tax benefit from continuing operations for the nine months ended September 30, 2013 was $1.9 million. The difference between the actual tax benefit of $1.9 million and the expected income tax benefit of $7.0 million, based on the Canadian enacted statutory rate of 25%, is primarily due to a goodwill impairment of $13.7 million, a $4.5 million increase in the valuation allowance, $6.2 million in dividend withholding and preferred share taxes, and $5.2 million of changes in estimates at joint venture projects. This is partially offset with $19.4 million related to Treasury grant proceeds, $3.9 million of foreign exchange, and $1.0 million of other permanent differences.

Income tax benefit for the nine months ended September 30, 2012 was $19.1 million. The difference between the actual tax benefit and the expected income tax benefit, based on the Canadian enacted statutory rate of 25%, of $28.4 million for the nine months ended September 30, 2012 is primarily due to foreign currency translation difference in tax rates in other countries, change in valuation allowance and various other permanent differences.

Generation and Availability

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Aggregate power generation (thousands of Net MWh) |  |  |  |  |  |  |  |  |  |
Northeast |  |  | 656.2 |  |  | 581.4 |  |  | 12.9 | %
Southeast(1) |  |  | 204.5 |  |  | 103.6 |  |  | 97.4 | %
Northwest |  |  | 498.9 |  |  | 287.0 |  |  | 73.8 | %
Southwest(2) |  |  | 824.3 |  |  | 541.6 |  |  | 52.2 | %
Total |  |  | 2,183.9 |  |  | 1,513.6 |  |  | 44.3 | %
Weighted average availability |  |  |  |  |  |  |  |  |  |
Northeast |  |  | 98.1 | % |  | 97.5 | % |  | 0.6 | %
Southeast(1) |  |  | 95.6 | % |  | 100.0 | % |  | -4.4 | %
Northwest |  |  | 87.7 | % |  | 94.3 | % |  | -7.0 | %
Southwest(2) |  |  | 94.0 | % |  | 96.1 | % |  | -2.2 | %
Total |  |  | 94.9 | % |  | 96.7 | % |  | -1.9 | %

(1)
  Excludes the Florida Projects which are designated as discontinued operations.
(2)
  Excludes Delta-Person for which we have entered into an agreement to sell and Gregory which was sold on August 7, 2013.

Three months ended September 30, 2013 compared with three months ended September 30, 2012

Aggregate power generation for the three months ended September 30, 2013 increased 38.8% from the comparable 2012 period primarily due to:

•
  increased generation in the Northeast segment due to higher water flow at Curtis Palmer and increased dispatch at Chambers;

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•
  increased generation in the Southeast segment due to Piedmont, which achieved commercial operations in April 2013;
•
  increased generation in the Northwest segment primarily due to Meadow Creek, which achieved commercial operations in late December 2012, as well as generation from Goshen. Both projects were acquired in December 2012; and
•
  increased generation in the Southwest segment due to Canadian Hills, which achieved commercial operations in late December 2012 and increased dispatch at Manchief.

Weighted average availability decreased 1.9% from 96.7% for the three months ended September 30, 2012 to 94.9% for the three months ended September 30, 2013 period primarily due to:

•
  decreased availability in the Southeast segment resulting from Piedmont, which achieved commercial operations in April 2013 and had low availability consistent with the initial start-up period of a new plant;
•
  decreased availability in the Northwest segment resulting from decreased availability at Mamquam, Moresby Lake and Williams Lake which underwent scheduled maintenance during the three months ended September 30, 2013. This was partially offset by increased availability at Meadow Creek and Goshen which were acquired in December 2012; and
•
  decreased availability in the Southwest segment resulting from Morris due to a maintenance outage initiated in the second quarter of 2013 that extended into the third quarter of 2013, as well as a forced outage at Morris for a boiler repair.

This was partially offset by

•
  increased availability in the Northeast segment due to increased availability at Curtis Palmer due to higher water flows from the comparable period.

Each of the projects with reduced availability was nevertheless able to achieve substantially all of its respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.

Generation (in thousands of Net MWh) and availability statistics for the Southeast segment exclude the Florida Projects which are accounted for as a component of discontinued operations. Total generation for Auburndale was 275.1 MWh and availability was 99.1% for the three months ended September 30, 2012. Total generation for Lake was 120.8 MWh and availability was 99.8% for the three months ended September 30, 2012. Total generation for Pasco was 64.3 MWh and availability was 98.3% for the three months ended September 30, 2012. The Florida Projects were sold on April 12,

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2013, resulting in no generation or availability statistics for the three months ended September 30, 2013.

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Aggregate power generation (thousands of Net MWh) |  |  |  |  |  |  |  |  |  |
Northeast |  |  | 1,994.0 |  |  | 1,783.2 |  |  | 11.8 | %
Southeast(1) |  |  | 491.0 |  |  | 312.0 |  |  | 57.4 | %
Northwest |  |  | 1,227.5 |  |  | 847.4 |  |  | 44.9 | %
Southwest(2) |  |  | 2,460.0 |  |  | 1,457.6 |  |  | 68.8 | %
Total |  |  | 6,172.5 |  |  | 4,400.2 |  |  | 40.3 | %
Weighted average availability |  |  |  |  |  |  |  |  |  |
Northeast |  |  | 96.9 | % |  | 96.0 | % |  | 0.9 | %
Southeast(1) |  |  | 95.6 | % |  | 100.0 | % |  | -4.4 | %
Northwest |  |  | 89.2 | % |  | 94.2 | % |  | -5.3 | %
Southwest(2) |  |  | 93.1 | % |  | 94.5 | % |  | -1.5 | %
Total |  |  | 94.3 | % |  | 95.5 | % |  | -1.3 | %

(1)
  Excludes the Florida Projects which are designated as discontinued operations.
(2)
  Excludes Delta-Person for which we have entered into an agreement to sell and Gregory which was sold on August 7, 2013.

Nine months ended September 30, 2013 compared with nine months ended September 30, 2012

Aggregate power generation for the nine months ended September 30, 2013 increased 38.4% from the comparable 2012 period primarily due to:

•
  increased generation in the Northeast segment due to increased dispatch at Chambers and Selkirk;
•
  increased generation in the Southeast segment due to Piedmont, which achieved commercial operations in April 2013;
•
  increased generation in the Northwest segment primarily due to Meadow Creek, which achieved commercial operations in late December 2012, as well as generation from Goshen and increased ownership of Rockland, all of which resulted from our December 2012 acquisition of Ridgeline; and
•
  increased generation in the Southwest segment due to Canadian Hills, which achieved commercial operations in late December 2012 and increased dispatch at Manchief.

Weighted average availability decreased 1.3% from 95.5% for the nine months ended September 30, 2012 to 94.3% for the nine months ended September 30, 2013 primarily due to:

•
  decreased availability in the Southeast segment resulting from Piedmont, which achieved commercial operations in April 2013 and had low availability consistent with the initial start-up period of a new plant;
•
  decreased availability in the Northwest segment resulting from decreased availability at Mamquam, Moresby Lake and Williams Lake which underwent scheduled maintenance during 2013. This was partially offset by increased availability at Meadow Creek and Goshen which were acquired in December 2012; and
•
  decreased availability in the Southwest segment resulting from scheduled maintenance at Morris during the second and third quarters of 2013 and a forced maintenance outage at Morris for a boiler repair.

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This was partially offset by

•
  increased availability in the Northeast segment due to Calstock, which had a scheduled maintenance outage in April 2012, and increased availability at Selkirk, which had higher dispatch than the comparable 2012 period.

Each of the projects with reduced availability was nevertheless able to achieve substantially all of its respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.

Generation (in thousands of Net MWh) and availability statistics for the Southeast segment exclude the Florida Projects which are accounted for as a component of discontinued operations. Total generation for Auburndale was 731.3 MWh and availability was 98.8% for the nine months ended September 30, 2012. Total generation for Lake was 361.4 MWh and availability was 99.2% for the nine months ended September 30, 2012. Total generation for Pasco was 205.9 MWh and availability was 96.9% for the nine months ended September 30, 2012. The Florida Projects were sold on April 12, 2013, resulting in no generation or availability statistics for the three months ended September 30, 2013. Total generation for Auburndale was approximately 270 MWh and availability was approximately 98.8% for the nine months ended September 30, 2013. Total generation for Lake was approximately 240 MWh and availability was approximately 97.3% for the nine months ended September 30, 2013. Total generation for Pasco was approximately 40 MWh and availability was approximately 91.6% for the nine months ended September 30, 2013.

Supplementary Non-GAAP Financial Information

A key measure we use to evaluate the results of our business is Cash Available for Distribution. Cash Available for Distribution is not a measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. We believe Cash Available for Distribution is a relevant supplemental measure of our ability to pay dividends to our shareholders. A reconciliation of cash flows from operating activities, the most directly comparable GAAP measure, to Cash Available for Distribution is set out below under "Cash Available for Distribution." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

The primary factor influencing Cash Available for Distribution is cash distributions received from the projects. These distributions received are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service, capital expenditures, dividends paid on preferred shares of a subsidiary company, distributions to noncontrolling interests and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of project income (loss) to Project Adjusted EBITDA is set out below by segment under "Project Adjusted EBITDA" and a reconciliation of project income (loss) by segment to Project Adjusted EBITDA by segment is set out in Note 13 to the consolidated financial statements of this Quarterly Report on Form 10-Q. Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

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Project Adjusted EBITDA

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
(unaudited) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Project Adjusted EBITDA by Segment |  |  |  |  |  |  |  |  |  |  |  |  |
Northeast |  | $ | 24.9 |  | $ | 20.3 |  | $ | 96.8 |  | $ | 85.2 |
Southeast(1) |  |  | 5.9 |  |  | 2.3 |  |  | 10.4 |  |  | 6.5 |
Northwest |  |  | 19.4 |  |  | 12.6 |  |  | 53.0 |  |  | 38.5 |
Southwest(2) |  |  | 29.5 |  |  | 23.4 |  |  | 64.5 |  |  | 48.0 |
Un-allocated Corporate(3) |  |  | (3.5 | ) |  | (1.2 | ) |  | (11.4 | ) |  | (7.5 | )
Total |  |  | 76.2 |  |  | 57.4 |  |  | 213.3 |  |  | 170.7 |
Reconciliation to project income (loss) |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 51.4 |  |  | 41.8 |  |  | 154.5 |  |  | 123.0 |
Interest, net |  |  | 10.6 |  |  | 5.8 |  |  | 30.5 |  |  | 18.1 |
Change in the fair value of derivative instruments |  |  | 3.5 |  |  | (10.8 | ) |  | (34.8 | ) |  | 48.9 |
Other expense |  |  | 5.9 |  |  | 0.9 |  |  | 5.8 |  |  | 4.4 |
Project income (loss) |  |  | 4.8 |  |  | 19.7 |  |  | 57.3 |  |  | (23.7 | )

(1)
  Excludes the Florida Projects which are designated as discontinued operations.
(2)
  Excludes Path 15 which is designated as discontinued operations.
(3)
  Excludes Rollcast which is designated as discontinued operations.

Northeast

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

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Northeast |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 24.9 |  | $ | 20.3 |  |  | 23 | %

Three months ended September 30, 2013 compared with three months ended September 30, 2012

Project Adjusted EBITDA for the three months ended September 30, 2013 increased $4.6 million or 23% from the comparable 2012 period primarily due to increases in Project Adjusted EBITDA of:

•
  $3.5 million at Curtis Palmer primarily attributable to increased generation resulting from higher water levels than the comparable period; and
•
  $1.0 million at Selkirk due to higher generation and escalation of capacity payments as well as total increased Project Adjusted EBITDA of $3.6 million across the remaining Northeast projects.

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

•
  $3.5 million at Nipigon primarily attributable to higher fuel costs and higher maintenance costs resulting from a scheduled outage during the period.

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Northeast |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 96.8 |  | $ | 85.2 |  |  | 14 | %

Nine months ended September 30, 2013 compared with nine months ended September 30, 2012

Project Adjusted EBITDA for the nine months ended September 30, 2013 increased $11.6 million or 14% from the comparable 2012 period primarily due to increases in Project Adjusted EBITDA of:

•
  $6.3 million at Curtis Palmer primarily attributable to increased generation resulting from higher water levels to the comparable period and a $2.3 million favorable property tax assessment during 2013;
•
  $5.0 million at Calstock which had a steam turbine maintenance outage occur in the comparable 2012 period;
•
  $3.2 million at Kenilworth primarily attributable to increased capacity revenues under the month to month renewal of the project's energy service arrangement; and
•
  $2.8 million at Selkirk due to capacity revenues resulting from higher generation, partially offset by higher fuel costs.

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

•
  $3.2 million at Chambers primarily attributable to the collection of the DuPont partial settlement associated with the dispute of the electricity calculation under its PPA in the second quarter of 2012; and
•
  $2.4 million at Tunis resulting from lower generation and higher maintenance costs due to a scheduled outage.

Southeast

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

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Southeast |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 5.9 |  | $ | 2.3 |  |  | 157 | %

Three months ended September 30, 2013 compared with three months ended September 30, 2012

Project Adjusted EBITDA in the Southeast segment increased $3.6 million from the comparable 2012 period. Piedmont, which achieved commercial operations in April 2013, had $3.5 million of Project Adjusted EBITDA for the three months ended September 30, 2013.

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Project Adjusted EBITDA for the Southeast segment excludes the Florida Projects which are accounted for as a component of discontinued operations and were sold in April 2013. Project Adjusted EBITDA for Auburndale, Lake and Pasco was $12.7 million, $8.9 million and ($0.8) million, respectively, for the three months ended September 2012.

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Southeast |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 10.4 |  | $ | 6.5 |  |  | 60 | %

Nine months ended September 30, 2013 compared with nine months ended September 30, 2012

Project Adjusted EBITDA in the Southeast segment increased $3.9 million or 60% from the comparable 2012 period. Piedmont, which achieved commercial operations in April 2013, had $3.7 million of Project Adjusted EBITDA for the nine months ended September 30, 2013.

Project Adjusted EBITDA for the Southeast segment excludes the Florida Projects which are accounted for as a component of discontinued operations. Project Adjusted EBITDA for Auburndale was $12.4 million and $36.2 million for the nine months ended September 30, 2013 and 2012, respectively, Project Adjusted EBITDA for Lake was $13.7 million and $26.2 million for the nine months ended September 30, 2013 and 2012, respectively and Project Adjusted EBITDA for Pasco was $1.2 million and $1.0 million for the nine months ended September 30, 2013 and 2012, respectively. The decrease is attributable to the projects being sold in April 2013.

Northwest

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

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Northwest |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 19.4 |  | $ | 12.6 |  |  | 54 | %

Three months ended September 30, 2013 compared with three months ended September 30, 2012

Project Adjusted EBITDA for the three months ended September 30, 2013 increased by $6.8 million or 54% from the comparable 2012 period primarily due to increases in Project Adjusted EBITDA of:

•
  $3.9 million at Meadow Creek which achieved commercial operations in December 2012; and
•
  $2.1 million at Rockland attributable to the 100% consolidation of a former equity method project subsequent to an ownership change from 30% to 50% as part of the Ridgeline acquisition in December 2012.

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Northwest |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 53.0 |  | $ | 38.5 |  |  | 38 | %

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Nine months ended September 30, 2013 compared with nine months ended September 30, 2012

Project Adjusted EBITDA for the nine months ended September 30, 2013 increased by $14.5 million or 38% from the comparable 2012 period primarily due to increases in Project Adjusted EBITDA of:

•
  $10.4 million at Meadow Creek which achieved commercial operations in December 2012;
•
  $5.0 million at Rockland attributable to the 100% consolidation as discussed above; and
•
  $2.4 million at Goshen attributable to the project acquired as part of the Ridgeline acquisition in December 2012.

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

•
  $4.1 million at Mamquam resulting from higher maintenance costs due to a scheduled outage and decreased revenues caused by lower water levels.

Southwest

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

|  | Three months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Southwest |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 29.5 |  | $ | 23.4 |  |  | 26 | %

Three months ended September 30, 2013 compared with three months ended September 30, 2012

Project Adjusted EBITDA for the three months ended September 30, 2013 increased by $6.1 million or 26% from the comparable 2012 period primarily due to increases in Project Adjusted EBITDA of:

•
  $3.7 million at Canadian Hills which became commercially operational in December 2012; and
•
  $1.7 million at Morris attributable to higher steam sales and lower maintenance costs than the comparable period.

|  | Nine months ended September 30, |
--- | --- | --- | ---
|  | 2013 |  | 2012 |  | % change 2013 vs. 2012 |
Southwest |  |  |  |  |  |  |  |  |  |
Project Adjusted EBITDA |  | $ | 64.5 |  | $ | 48.0 |  |  | 34 | %

Nine months ended September 30, 2013 compared with nine months ended September 30, 2012

Project Adjusted EBITDA for the nine months ended September 30, 2013 increased by $16.5 million or 34% from the comparable 2012 period primarily due to increases in Project Adjusted EBITDA of:

•
  $18.4 million at Canadian Hills which became commercially operational in December 2012; and

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•
  $2.3 million at Gregory attributable to a planned major inspection that was completed during 2012, resulting in higher operations and maintenance expense in the comparable period and also attributable to an increased gross margin in 2013 due to higher energy prices.

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

•
  $2.9 million at Morris attributable to higher maintenance costs, higher fuel expenses, and lower revenues than the comparable period.

Project Adjusted EBITDA for the Southwest segment excludes the Path 15 project which is accounted for as a component of discontinued operations and was sold on April 30, 2013. Project Adjusted EBITDA for Path 15 was $9.0 million for the nine months ended September 30, 2013 and $6.2 million and $17.3 million for the three and nine months ended September 30, 2012, respectively.

Cash Available for Distribution

The payout ratio associated with the cash dividends declared to shareholders was 29% and 120% for the three months ended September 30, 2013 and 2012 respectively, and 43% and 98% for the nine months ended September 30, 2013 and 2012, respectively. On February 28, 2013, we announced a reduction in the dividend level from a monthly dividend level of Cdn$0.09583 to Cdn$0.03333 commencing with the March 2013 dividend to shareholders of record on March 28, 2013. The payout ratio for the three and nine months ended September 30, 2013 as compared to the same period in 2012 was positively impacted by the reduced cash dividends declared to shareholders as well as the inclusion of operating results from Canadian Hills and Meadow Creek which achieved commercial operations in late December 2012. This was partially offset by lower operating cash flows as a result of the sale of the Florida Projects and Path 15 in April 2013. Due to the timing of numerous working capital adjustments and the cash payments associated with our corporate level interest payments, our payout ratio will fluctuate from quarter to quarter. For example, the interest payments on the $460 million Senior Notes are due semi-annually (May and November) and will impact our payout ratios in the second and fourth quarters.

The table below presents our calculation of Cash Available for Distribution for the three and nine months ended September 30, 2013 and 2012, and the reconciliation to cash flows from operating activities, the most directly comparable GAAP measure:

(unaudited) |  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
(in millions of U.S. dollars, except as otherwise stated) |  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Cash flows from operating activities |  | $ | 46.4 |  | $ | 34.7 |  | $ | 143.3 |  | $ | 124.1 |
Project-level debt repayments |  |  | (1.7 | ) |  | (2.7 | ) |  | (12.2 | ) |  | (12.1 | )
Purchases of property, plant and equipment |  |  | (2.2 | ) |  | (0.4 | ) |  | (7.3 | ) |  | (1.2 | )
Dividends on preferred shares of a subsidiary company |  |  | (3.2 | ) |  | (3.3 | ) |  | (9.5 | ) |  | (9.8 | )
Distributions to noncontrolling interests(1) |  |  | (1.4 | ) |  | — |  |  | (4.4 | ) |  | — |
Cash Available for Distribution(2) |  |  | 37.9 |  |  | 28.3 |  |  | 109.9 |  |  | 101.0 |
Total cash dividends declared to shareholders |  |  | 11.0 |  |  | 34.0 |  |  | 47.2 |  |  | 99.1 |
Payout ratio |  |  | 29 | % |  | 120 | % |  | 43 | % |  | 98 | %

(1)
  During the three months ended September 30, 2013, we adjusted the calculation for Cash Available for Distribution to exclude distributions to noncontrolling interests because we believe it more accurately presents the cash available to be distributed to our common shareholders. As a result of the adjustment, cash available for distribution decreased from $(6.7) million to $(8.7) million and from $75.0 million to $72.1 million for the three and six months ended June 30, 2013, respectively. The payout ratio increased from (165)% to (126)% and from 48% to 50% for the three and six months ended June 30, 2013, respectively. Cash available for distribution and payout ratio did not change materially for the three months ended March 31, 2013. Distributions to noncontrolling

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interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland.

(2)
  Cash Available for Distribution is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP. Therefore, this measure may not be comparable to similar measures presented by other companies. See "Supplementary Non-GAAP Financial Information" above.

Consolidated Cash Flows

At September 30, 2013, cash and cash equivalents increased approximately $110.5 million from December 31, 2012 to $170.7 million. The increase in cash and cash equivalents was due to $143.3 million provided by operating activities and $147.6 million provided by investing activities offset by $(186.6) million of cash used in financing activities. The operating, investing and financing activities include the Florida Projects, Path 15 and Rollcast discontinued operations. There was $6.5 million of cash located at the Florida and Path 15 projects at December 31, 2012.

At September 30, 2012, cash and cash equivalents decreased $17.8 million from December 31, 2011 to $42.9 million. The decrease in cash and cash equivalents was primarily due to $(415.5) million of cash used in financing activities, offset by $124.1 million provided by operating activities and $275.4 million of cash provided by investing activities.

|  | Nine months ended September 30, |  | $ Change |
--- | --- | --- | --- | --- | ---
|  | 2013 vs. 2012 |
|  | 2013 |  | 2012 |
Net cash provided by operating activities |  | $ | 143.3 |  | $ | 124.1 |  | $ | 19.2 |
Net cash provided by (used in) investing activities |  |  | 147.6 |  |  | (415.5 | ) |  | 563.1 |
Net cash (used in) provided by financing activities |  |  | (186.6 | ) |  | 275.4 |  |  | (462.0 | )

Operating Activities

Our cash flow from the projects may vary from year to year 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 market 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.

Cash flow from operating activities increased by $19.2 million for the nine months ended September 30, 2013 from the comparable period in 2012. The change from the prior year is primarily attributable to the increases in Project Adjusted EBITDA noted above.

Investing Activities

Cash flow from investing activities includes changes in restricted cash. Restricted cash fluctuates from period to period in part because non-recourse project-level financing arrangements typically require all operating cash flow from the project to be deposited in restricted accounts and then released at the time that principal payments are made and project-level debt service coverage ratios are met. As a result, the timing of principal payments on project-level debt causes significant fluctuations in restricted cash balances, which typically benefits investing cash flow in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year.

Cash flow provided by (used in) investing activities includes cash used to fund acquisitions and construct development projects in North American markets. Cash flows provided by investing activities for the nine months ended September 30, 2013 were $147.6 million compared to cash flows used in investing activities of $(415.5) million for the nine months ended September 30, 2012. The change is

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due to a $336.2 million increase of cash used in construction costs related to the Piedmont and Canadian Hills projects, which both completed construction and achieved commercial operations during 2013, partially offset by $183.0 million in cash received for the sale of the Florida Projects, Path 15 and Gregory project and $103.2 million in treasury grant proceeds received for Meadow Creek and Piedmont in the nine months ended September 30, 2013.

Financing Activities

Cash used in financing activities for the nine months ended September 30, 2013 resulted in a net outflow of $186.6 million compared to a net inflow of $275.4 million for the comparable 2012 period. The change from the prior year is due to proceeds from long-term debt primarily attributable to a $176.1 million construction loan proceeds received for the Canadian Hills construction loan in the nine months ended September 30, 2012 and $115.3 million of repayments of project level debt primarily related to Meadow Creek and Piedmont's construction debt paid down with treasury grant proceeds. This was partially offset by a $40.0 million decrease in dividends paid to common shareholders and $44.6 million received in equity contributions from noncontrolling interests at Canadian Hills.

Liquidity and Capital Resources

(in millions of U.S. dollars, except as otherwise stated) |  | September 30, 2013 |  | December 31, 2012 |
--- | --- | --- | --- | --- | ---
Cash and cash equivalents |  | $ | 170.7 |  | $ | 60.2 |
Restricted cash |  |  | 119.8 |  |  | 28.6 |
Total |  |  | 290.5 |  |  | 88.8 |
Senior credit facility availability |  |  | 58.8 |  |  | 120.1 |
Total liquidity |  | $ | 349.3 |  | $ | 208.9 |

These amounts may be further reduced as a result of the outcome of our discussions with a natural gas supplier for additional security in the form of cash, letters of credit or a combination of both.

Overview

Our primary sources of liquidity are cash on hand, distributions from our projects and availability of letters of credit under our senior credit facility. Substantially all of the cash received from project distributions is used to pay dividends to our common and preferred shareholders, in each case, if and when declared by the board of directors, and interest on our outstanding convertible debentures, senior notes and other corporate-level debt. Our liquidity depends in part on our ability to successfully enter into new PPAs at facilities where PPAs expire or terminate. PPAs in our portfolio have expiration dates ranging from August 2014 to December 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, which may reduce the cash received from project distributions. We may fund future acquisitions with a combination of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt, although we can provide no assurances regarding the availability of public or private financing on acceptable terms or at all.

As of November 7, 2013, there are no debt instruments with maturities in 2013. In April 2013, we utilized a portion of the net proceeds received from the sale of the Florida Projects to fully repay our senior credit facility which had an outstanding balance of $64.1 million at sale of the Florida Projects. At November 7, 2013, our senior credit facility was undrawn and the applicable margin was 4.25%. As

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of November 7, 2013, $91.2 million was issued in letters of credit, but not drawn, to support contractual credit requirements at several of our projects.

We must meet certain financial covenants under the terms of our senior credit facility, which are generally based on ratios as described in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2013 and in Note 9 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2012.

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 the next 12 months.

On August 2, 2013 we entered into an amendment to our prior senior credit facility. The most significant changes to the prior senior credit facility as a result of the amendment include the following:

•
  a decrease in capacity from $300 million to $150 million, all of which may be utilized for letters of credit (as compared to the previous $200 million that could have been utilized for letters of credit) and a sublimit of $25 million which may be utilized for other borrowings;
•
  a requirement to cash collateralize outstanding letters of credit in an amount equal to the excess above $125 million if the aggregate amount of letters of credit and borrowings outstanding under the senior facility exceeds $125 million;
•
  a requirement to maintain at all times unrestricted cash and cash equivalents of at least $75 million (inclusive of any cash collateral provided as described above), which amounts shall be pledged to the lenders as security for the senior credit facility;
•
  an amendment to the maximum permissible Consolidated Total Net Debt to Consolidated EBITDA ratio (each as defined in the senior credit facility) to 7.75 to 1.00 (as compared to a prior ratio of 7.50 to 1.00 declining to 7.00 to 1.00 over time);
•
  an amendment to the minimum permissible Consolidated EBITDA to Consolidated Interest Expense (each as defined in the senior credit facility) ratio to 1.60 to 1.00 (as compared to a prior ratio of 2.25 to 1.00);
•
  a requirement to pay a commitment fee of between 0.75% and 1.75% per year based on a percentage of the amount committed under the senior credit facility, which fee varies based on our unsecured debt rating (at September 30, 2013, the applicable commitment fee was 1.50%); and
•
  an amendment to the maturity date from November 4, 2015 to March 4, 2015.

Among other restrictions set forth in the senior credit facility, we are restricted from paying cash dividends to our shareholders if we do not comply with the financial covenants specified above. The senior credit facility is secured by pledges of certain assets and interests in certain subsidiaries. The prior senior credit facility contained customary representations, warranties, terms and conditions, and covenants, certain of which were amended in connection with the amendment to the senior credit facility. The covenants in the senior credit facility limit our ability to, among other things, incur additional indebtedness, merge or consolidate with others, make acquisitions, change our business and sell or dispose of assets. These covenants also include limitations on investments, limitations on dividends and other restricted payments, limitations on entering into certain types of restrictive agreements, limitations on transactions with affiliates and limitations on the use of proceeds from the senior credit facility. Specifically, under the senior credit facility, we are effectively only permitted to make voluntary prepayments or repurchases of our outstanding debt (including for these purposes subsidiary debt guaranteed by us) from the proceeds of debt permitted to be incurred to refinance that outstanding debt or during the 60-day period preceding the maturity of that outstanding debt. Under

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the senior credit facility, we had the right generally to repurchase substantially more of our outstanding debt issuances, subject to the satisfaction of certain conditions. In the amendment, the lenders also consented to (i) our previously announced sale of Delta-Person and (ii) the sale of AP Onondaga, LLC, Onondaga Renewables, LLC and their property.

Borrowings under the senior credit facility are available in U.S. dollars and Canadian dollars and bear interest at a variable rate equal to the US Prime Rate, the Eurocurrency LIBOR Rate or the Cdn. Prime Rate (each as defined in the amended credit facility), as applicable, plus a margin of between 1.75% and 4.75% that varies based on our unsecured debt rating. At September 30, 2013, the applicable margin for loans bearing interest at the Eurocurrency LIBOR Rate and for the outstanding letters of credit is 4.25%. The foregoing summary is qualified in its entirety by reference to the senior credit facility which has been filed as an exhibit to our Current Report on Form 8-K on August 5, 2013 and is incorporated by reference as an exhibit to this Quarterly Report on Form 10-Q.

We expect to meet covenants under the senior credit facility for the next twelve months. As of November 7, 2013, we were in compliance with these covenants.

We have certain financial covenants that must be met under the terms of our 9% senior unsecured notes, including a restricted payments covenant that includes a Consolidated EBITDA to Consolidated Interest Expense ratio. As of November 7, 2013, we were in compliance with these ratios. As previously disclosed, we continue to believe that it is likely, during the third quarter of 2014, that we may not meet the provision requiring that our Fixed Charge Coverage Ratio (included in the restricted payments covenant in the indenture governing our 9% senior unsecured notes) be no less than 1.75 to 1.00. We are currently considering various initiatives to address our upcoming debt maturities, reduce our leverage, improve our financial flexibility, reduce expenses and optimize our assets. Because we are at the preliminary stages of considering such initiatives and options, we cannot provide any assurances that any of them will be successful. These or other actions that we may take to achieve our highest priority financial objectives could have an adverse impact on the dividend level. Also, we cannot predict the impact, if any, that these initiatives or options will have on our ability to remain in compliance with the Fixed Charge Coverage Ratio through the third quarter of 2014. If we are not in compliance with this covenant, dividend payments in the aggregate must not exceed the basket provision in such covenant of the greater of $50 million and 2% of Consolidated Net Assets (approximately $68 million at September 30, 2013). Based on the current dividend level, we believe that this basket, at the discretion of the Board of Directors, could permit the payment of the dividend, if and when declared by the Board of Directors, at the current level for at least 12 months beyond a determination of non-compliance. Additionally, during any potential period of non-compliance, we would be permitted under other basket provisions of the indenture to borrow up to $350 million under a revolving credit facility and incur additional indebtedness of up to 15% of Consolidated Net Assets (approximately $500 million at September 30, 2013). Dividends or borrowings made in compliance with such basket provisions would not trigger an event of default under such indenture or a cross-default with respect to our other indebtedness.

Defined terms used in the foregoing discussion are as defined in the indenture governing the 9% senior unsecured notes and the foregoing summary is qualified in its entirety by reference to such indenture, which has been filed as an exhibit to our Annual Report on Form 10-K.

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Corporate Debt

The following table summarizes the maturities of our corporate debt at September 30, 2013:

|  | Interest Rates |  | Total Remaining Principal Repayments |  | 2013 |  | 2014 |  | 2015 |  | 2016 |  | 2017 |  | Thereafter |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Atlantic Power Corporation Notes |  |  | 9.0 | % | $ | 460.0 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 460.0 |
Atlantic Power US (GP) Note |  |  | 6.0 | % |  | 150.0 |  |  | — |  |  | — |  |  | 150.0 |  |  | — |  |  | — |  |  | — |
Atlantic Power US (GP) Note |  |  | 5.9 | % |  | 75.0 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 75.0 |  |  | — |
Atlantic Power Income LP Note |  |  | 6.0 | % |  | 203.8 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 203.8 |
Convertible Debenture |  |  | 6.5 | % |  | 43.5 |  |  | — |  |  | 43.5 |  |  | — |  |  | — |  |  | — |  |  | — |
Convertible Debenture |  |  | 6.3 | % |  | 65.5 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 65.5 |  |  | — |
Convertible Debenture |  |  | 5.6 | % |  | 78.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 78.1 |  |  | — |
Convertible Debenture |  |  | 5.8 | % |  | 130.0 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 130.0 |
Convertible Debenture |  |  | 6.0 | % |  | 97.0 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 97.0 |
Total Corporate Debt |  |  |  |  | $ | 1,302.9 |  | $ | — |  | $ | 43.5 |  | $ | 150.0 |  | $ | — |  | $ | 218.6 |  | $ | 890.8 |

Project-Level Debt

The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse project-level debt balances at September 30, 2013. 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. All project-level debt is non-recourse to us and substantially all of the principal is amortized over the life of the projects' PPAs. The non-recourse holding company debt relating to our investment in Chambers is held at Epsilon Power Partners, our wholly owned subsidiary.

The range of interest rates presented represents the rates in effect at September 30, 2013. The amounts listed below are in millions of U.S. dollars, except as otherwise stated.

|  | Range of Interest Rates |  | Total Remaining Principal Repayments |  | 2013 |  | 2014 |  | 2015 |  | 2016 |  | 2017 |  | Thereafter |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Consolidated Projects: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Epsilon Power Partners |  | 7.4% |  | $ | 31.2 |  | $ | 0.8 |  | $ | 5.0 |  | $ | 5.8 |  | $ | 6.0 |  | $ | 6.2 |  | $ | 7.4 |
Piedmont(1) |  | 3.8% – 5.2% |  |  | 76.6 |  |  | 4.1 |  |  | 4.5 |  |  | 4.5 |  |  | 3.4 |  |  | 2.9 |  |  | 57.2 |
Cadillac |  | 6.0% – 8.0% |  |  | 36.0 |  |  | 0.6 |  |  | 2.0 |  |  | 3.9 |  |  | 2.5 |  |  | 3.0 |  |  | 24.0 |
Rockland |  | 6.4% |  |  | 85.8 |  |  | 0.4 |  |  | 1.5 |  |  | 1.8 |  |  | 1.9 |  |  | 2.2 |  |  | 78.0 |
Curtis Palmer(2) |  | 5.9% |  |  | 190.0 |  |  | — |  |  | 190.0 |  |  | — |  |  | — |  |  | — |  |  | — |
Meadow Creek |  | 2.9 – 5.1% |  |  | 171.4 |  |  | 1.6 |  |  | 4.9 |  |  | 4.6 |  |  | 5.3 |  |  | 5.3 |  |  | 149.7 |
Total Consolidated Projects |  |  |  |  | 591.0 |  |  | 7.5 |  |  | 207.9 |  |  | 20.6 |  |  | 19.1 |  |  | 19.6 |  |  | 316.3 |
Equity Method Projects: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Chambers |  | 0.6% – 7.2% |  |  | 43.9 |  |  | 2.7 |  |  | 0.9 |  |  | 0.2 |  |  | 0.1 |  |  | — |  |  | 40.0 |
Delta-Person(3) |  | 1.9% |  |  | 6.8 |  |  | 0.3 |  |  | 1.3 |  |  | 1.4 |  |  | 1.5 |  |  | 1.1 |  |  | 1.2 |
Goshen |  | 3.0% – 6.6% |  |  | 24.3 |  |  | — |  |  | 0.4 |  |  | 0.5 |  |  | 0.7 |  |  | 0.9 |  |  | 21.8 |
Idaho Wind |  | 5.6% |  |  | 47.5 |  |  | 0.8 |  |  | 2.4 |  |  | 2.6 |  |  | 2.5 |  |  | 2.7 |  |  | 36.5 |
Total Equity Method Projects |  |  |  |  | 122.5 |  |  | 3.8 |  |  | 5.0 |  |  | 4.7 |  |  | 4.8 |  |  | 4.7 |  |  | 99.5 |
Total Project-Level Debt |  |  |  | $ | 713.5 |  | $ | 11.3 |  | $ | 212.9 |  | $ | 25.3 |  | $ | 23.9 |  | $ | 24.3 |  | $ | 415.8 |

(1)
  As of September 30, 2013 the balance of $76.6 million on the Piedmont debt consists of an $82.0 million construction loan ($76.6 million at September 30, 2013) that is expected to convert to a term loan in the fourth quarter of 2013. We expect to commence the repayment of the term loan in the fourth quarter of 2013.
(2)
  The Curtis Palmer Notes are not considered non-recourse project-level debt as these notes are guaranteed by the Partnership. Interest expense associated with the Curtis Palmer notes are recorded as a component of project income.
(3)
  We have entered into an agreement to sell our interest in the Delta-Person project and expect to close the sale in the first quarter of 2014.

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Uses of Liquidity

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

Capital and Major 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 major expenditures relate to planned repairs and maintenance and are expensed when incurred.

We expect to reinvest approximately $40 million in 2013 in its portfolio in the form of project capital expenditures and major maintenance expenses, which is increased from our previous expectation of $30 to $35 million. The additional investment is part of the effort to identify optimization initiatives at our existing businesses that increase shareholder value. As of September 30, 2013, we have reinvested $29.6 million. Significant expenditures incurred or to be incurred in the fourth quarter that were not included in the original forecast are for improvements at the Piedmont project made in October 2013, outlays associated with the Nipigon steam generator upgrade project and an outage at the North Island project that has been moved forward to expedite the installation of required upgrades to support an increase in interconnection capacity from 38 MW to 42 MW. As explained above, these investments are generally paid at the project level. We believe one of the benefits of our diverse fleet is that plant overhauls and other major 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 major 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 major maintenance expenses may exceed the level in 2013 or the projected level in 2014 as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and hydroelectric turbine upgrades.

In all cases, scheduled maintenance outages during the three and nine months ended September 30, 2013 and 2012 occurred at such times that did not adversely impact the facilities' availability requirements under their respective PPAs.

Recently Adopted and Recently Issued Accounting Guidance

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

Critical Accounting Policies

Goodwill

Goodwill is not amortized; instead, it is reviewed for impairment annually (in the fourth quarter) or more frequently if indicators of impairment exist. A significant amount of judgment is involved in determining if an indicator of impairment has occurred. Such indicators may include a prolonged

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decline in our market capitalization, deterioration in general economic conditions, adverse changes in the market in which a reporting unit operates, decreases in energy or capacity revenues as the result of re-contracting or increases in input costs that have a negative effect on earnings and cash flows, or a trend of negative or declining cash flows over multiple periods, among others. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill.

Our goodwill is allocated among and evaluated for impairment at the reporting unit level, which is one level below our operating segments. The goodwill is allocated among thirteen of our reporting units, of which seven are included in the Northeast segment ($104.5 million at September 30, 2013), three are included in the Northwest segment ($138.3 million at September 30, 2013) and three are included in the Southwest segment ($53.5 million at September 30, 2013).

Effective January 1, 2012, we adopted a standard that provides an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of a reporting unit is less than its carrying amount. We performed our annual goodwill impairment assessment for the year ended December 31, 2012 as of November 30, 2012. Based on our qualitative assessment of macroeconomic, industry, and market events and circumstances as well as the overall financial performance of the reporting units, we determined that the fair value of goodwill attributed to these reporting units was not less than its carrying amount. As such, the annual two-step impairment test was deemed not necessary to be performed for these reporting units.

During the second quarter of 2013, based on a prolonged decline in our market capitalization as compared to our market capitalization at the time of our 2012 qualitative test, we determined that it was appropriate to initiate a test of goodwill prior to our annual goodwill impairment test that would have occurred in the fourth quarter of 2013. We proceeded directly to the two-step quantitative impairment test for all of the reporting units and concluded the test during the third quarter of 2013.

Under the two-step quantitative impairment test, the evaluation of impairment involves comparing the current fair value of each reporting unit to its carrying value, including goodwill. For step one of the quantitative test, we determine the fair value of our reporting units using an income approach with discounted cash flow ("DCF") models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected power prices, generation, fuel costs and capital expenditure requirements. Most of these assumptions vary significantly among the reporting units. The discount rate applied to the DCF models represents the weighted average cost of capital ("WACC") consistent with the risk inherent in future cash flows and based upon an assumed capital structure, cost of long-term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the individual reporting units' WACC rate are estimated for each business with the assistance of valuation experts. Cash flow forecasts are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. These forecasts utilize historical plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We use historical experience to determine estimated future capital investment requirements.

In the event the estimated fair value of a reporting unit per the DCF model is less than the carrying value, additional analysis would be required. The additional analysis would compare the carrying amount of the reporting unit's goodwill with the implied fair value of that goodwill, which may involve the use of valuation experts. The implied fair value of goodwill is the excess of the fair value of the reporting unit over the fair value amounts assigned to all of the assets and liabilities of that unit as if the reporting unit was acquired in a business combination and the fair value of the reporting unit represented the purchase price. If the carrying value of goodwill exceeds its implied fair value, an

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impairment loss equal to such excess would be recognized, which could significantly and adversely impact reported results of operations and shareholders' equity.

Under step one of our goodwill impairment tests performed during the third quarter of 2013, the fair value of seven of our reporting units exceeded their carrying value. Under the income approach described above, we estimated the fair value of these reporting units exceeded their carrying value by a weighted average of approximately 85%. For the six reporting units that failed step one of the quantitative tests, we utilized the assistance of valuation experts to perform step two of the quantitative impairment test. For four of these reporting units, the implied fair value of their goodwill exceeded the carrying amount of the reporting unit's goodwill resulting in no impairment. For the remaining two reporting units, it was determined that goodwill was impaired at the Kenilworth reporting unit (Northeast segment) and the Naval reporting unit (Southwest segment). The total impairment recorded in the three months ended September 30, 2013 was $34.9 million.

The $30.8 million impairment at Kenilworth was due to lower forecasted capacity and energy prices compared to the assumptions at the time of the acquisition in November 2011. When performing our step 2 quantitative analysis, the increase in the intangible value associated with the new ESA entered into in July 2013 resulted in a lower implied goodwill value. At the time of its acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Kenilworth project were valued assuming a merchant basis for the period subsequent to the expiration of the project's original PPA in July 2012. As discussed above, these forecasted energy revenues on a merchant basis were higher than the current forecasted energy prices subsequent to the expiration of the new ESA. The $4.1 million impairment at the Naval reporting units was primarily due to increased uncertainty, not assumed at the time of the reporting units acquisition in 2011, in our ability to extend two of the projects lease and steam agreements upon their expiration. In addition, lower currently forecasted capacity and energy prices in California after the expiration of the PPAs compared to the forecast at the time of the acquisition in 2011 result in a lower business enterprise value which resulted in a lower implied goodwill value.

Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.

Off-Balance Sheet Arrangements

As of September 30, 2013, 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

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect our cash flows or the value of our holdings of financial instruments. The objective of market risk management is to minimize the impact that market risks have on our cash flows as described in the following paragraphs.

Our market risk-sensitive instruments and positions have been determined to be "other than trading." Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in fuel and electricity commodity prices, currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in fuel commodity prices, currency exchange rates or interest rates and the timing of transactions. See Note 6 to the consolidated financial statements, Derivative instruments and hedging activities for additional information.

Fuel Commodity Market Risk

Our current and future cash flows are impacted by changes in electricity, natural gas and coal prices. See "Item 1A. Risk Factors—Risks Related to Our Business and Our Projects—Our projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the profitability of the projects" in our Annual Report on Form 10-K for the year ended December 31, 2012. The combination of long-term energy sales and fuel purchase agreements is generally designed to mitigate the impacts to cash flows of changes in commodity prices by passing through changes in fuel prices to the buyer of the energy.

The operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. As of November 7, 2013, we have entered into natural gas swaps in order to effectively fix approximately 74% of our share of the expected natural gas purchases at the project during 2014 and 2015 and approximately 38% of our share of the expected natural gas purchases at the project during 2016 and 2017.

In April and June 2013, we entered into contracts for the purchase of natural gas beginning on November 1, 2013 and expiring on March 31, 2014 for the Tunis project in order to fix approximately 50% of the expected natural gas purchase requirement during that period. Adjusted for these transactions, projected annual cash distributions at Tunis in 2013 would change by approximately $1.6 million per $1.00/MMBtu change in the price of natural gas based on the current level of natural gas volumes used by the project.

Electricity Commodity Market Risk

Our current and future cash flows are impacted by changes in electricity prices when our projects operate with no PPA or projects that operate with PPAs that are based on spot market pricing. Our most significant exposure to market power prices is at the Chambers and Morris projects. At Chambers, our utility customer has the right to sell a portion of the plant's output into the spot power market if it is profitable to do so, and the Chambers project shares in the profits from these sales. In addition, during periods of low spot electricity prices the utility takes less generation, which negatively affects the project's operating margin. In 2013, projected cash distributions at Chambers would change by approximately $0.6 million per 10% change in the spot price of electricity based on a forecasted level of approximately $42/MWh and certain other assumptions. Our equity investment in the Chambers project is 40%. At Morris, the facility can sell approximately 100MW above the off-taker's demand into the grid at market prices. If market prices do not justify the increased generation the project has no requirement to sell power in excess of the off-taker's demand which can negatively

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impact operating margins. In 2013, projected cash distributions at Morris would change by approximately $1.0 million per 20% change in the spot price of electricity based on the current level of approximately 300,000 MWh grid sales and all other variables being held constant. We own 100% of the Morris project. See Item 1A. "Risk Factors—Risks Related to Our Business and Our Projects—Certain of our projects are exposed to fluctuations in the price of electricity, which may have a material adverse effect on the operating margin of these projects and on our business, results of operations and financial condition" in our Annual Report on Form 10-K for the year ended December 31, 2012.

When a PPA expires or is terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced and in some cases significantly. Our projects may not be able to secure a new agreement and could be exposed to sell power at spot market prices. See Item 1A. "Risk Factors—Risks Related to Our Business and Our Projects—The expiration or termination of our power purchase agreements could have a material adverse impact on our business; results of operations and financial condition" in our Annual Report on Form 10-K for the year ended December 31, 2012. It is possible that subsequent PPAs or the spot markets may not be available at prices that permit the operation of the project on a profitable basis. If this occurs, the affected project may temporarily or permanently cease operations.

Foreign Currency Exchange Risk

We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars but we pay dividends to shareholders, if and when declared by the board of directors, and interest on corporate level long-term debt and convertible debentures, predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on future payments of dividends to shareholders, if and when declared by the board of directors. We have executed this strategy utilizing cash flows from our projects that generate Canadian dollars and by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge an average of approximately 71% of any dividend and expected long-term debt and convertible debenture interest payments through 2015. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. At September 30, 2013, the forward contracts consist of contracts assumed in our acquisition of the Partnership with various expiration dates through December 2015 to purchase a total of Cdn$34.9 million at an average exchange rate of Cdn$1.108 per U.S. dollar. It is our intention to periodically consider extending or terminating these forward contracts. In April 2013, we terminated various foreign currency forward contracts with expiration dates through June 2015 assumed in our acquisition of the Partnership, resulting in proceeds of $9.4 million.

The foreign exchange forward contracts are recorded at estimated fair value based on quoted market prices and the estimation of the counter-party's credit risk. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

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The following table contains the components of recorded foreign exchange (gain) loss for the three and nine months ended September 30, 2013 and 2012 (in millions):

|  | Three months ended September 30, |  | Nine months ended September 30, |
--- | --- | --- | --- | --- | ---
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Unrealized foreign exchange (gain) loss: |  |  |  |  |  |  |  |  |  |  |  |  |
Convertible debentures and other |  | $ | 10.4 |  | $ | 14.5 |  | $ | (17.0 | ) | $ | 13.4 |
Forward contracts |  |  | (0.2 | ) |  | (4.7 | ) |  | 18.5 |  |  | 8.2 |
|  |  | 10.2 |  |  | 9.8 |  |  | 1.5 |  |  | 21.7 |
Realized foreign exchange gains on forward contract settlements |  |  | (1.1 | ) |  | (2.1 | ) |  | (14.4 | ) |  | (17.3 | )
Total foreign exchange gain |  | $ | 9.1 |  | $ | 7.7 |  | $ | (12.9 | ) | $ | 4.4 |

The U.S. dollar to Canadian dollar exchange rate was 1.0303 at September 30, 2013. The following table illustrates the impact on the fair value of our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of September 30, 2013 (in millions) and does not consider local currency cash flows from our Canadian operating assets:

Convertible debentures denominated in Canadian dollars, at carrying value |  | $ | (25.8 | )
Foreign currency forward contracts |  | $ | 3.3 |

Interest Rate Risk

Changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 95% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use of interest rate swaps. After considering the impact of interest rate swaps described below, a hypothetical change in the average interest rate of 100 basis points would change annual interest costs, including interest at equity investments, by approximately $1.0 million.

Cadillac

We have an interest rate swap at our consolidated Cadillac project to economically fix its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Cadillac debt and changes in their fair market value are recorded in other comprehensive income (loss). The interest rate swap expires on September 30, 2025.

In accounting for the cash flow hedge, gains and losses on the derivative contract are reported in other comprehensive income (loss), but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income (loss). That is, for cash flow hedge, all effective components of the derivative contract's gains and losses are recorded in other comprehensive income (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) consists of those financial items that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets but not included in our net income (loss). Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on net income (loss) until the expected transaction occurs.

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Piedmont

We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements are not designated as hedges and changes in their fair market value are recorded in the statements of operations. The interest rate swaps expire on February 29, 2016 and November 30, 2030, respectively.

Epsilon Power Partners

Epsilon Power Partners, a wholly owned subsidiary, has an interest rate swap to economically fix the exposure to changes in interest rates related to the variable-rate non-recourse debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 7.4% and a maturity date of July 2019. The notional amount of the swap matches the outstanding principal balance over the remaining life of Epsilon Power Partners' debt. This interest rate swap agreement is not designated as a hedge and changes in its fair market value are recorded in the consolidated statements of operations.

Meadow Creek

Meadow Creek executed interest rate swaps that we assumed in our acquisition to economically fix the exposure to changes in interest rates related to 75% of the outstanding variable-rate non-recourse debt. These swaps effectively modify the project's exposure by converting the project's floating rate debt to a fixed basis. The interest rate swaps are with various counterparties and swap the expected interest payments from floating LIBOR to fixed rates structured in two tranches. The first tranche is for the notional amount due of the term loan commencing on December 30, 2012 and ending December 31, 2024 and fixes the interest rate at 2.3% plus an applicable margin of 2.8%—3.3%. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2024 and ends on December 31, 2030 fixing the interest rate at 7.2%.

Rockland

The Rockland project entered into interest rate swaps to manage interest rate risk exposure. These swaps effectively modify the project's exposure by converting the project's floating rate debt to a fixed basis. The interest rate swaps are with various counterparties and swap 100% of the expected interest payments from floating LIBOR to fixed rates structured in two tranches. The first tranche is for the notional amount due on the term loan commencing on December 30, 2011 and ending December 31, 2026 and fixes the interest rate at 4.2% plus an applicable margin of 2.3%—2.8%. The second tranche is the post-term portion of the loan, or the balloon payment and commences on December 31, 2026 and ends on December 31, 2031 fixing the interest rate at 7.8%.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report, 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 three and nine months ended September 30, 2013, that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Inherent Limitations of Disclosure Controls and Internal Control over Financial Reporting

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

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

Shareholder class action lawsuits

Massachusetts District Court Actions

On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against Atlantic Power and Barry E. Welch, our President and Chief Executive Officer and a Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the "Individual Defendants," and together with Atlantic Power, the "Defendants") (the "U.S. Actions").

The District Court complaints differ in terms of the identities of the Individual Defendants they name, as noted above, the named plaintiffs, and the purported class period they allege (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleges, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The District Court complaints assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.

The parties to each District Court action have filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the "Amended Complaint"), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and (iii) confirming that Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the "U.S. Lead Plaintiff Applicants") filed a motion (collectively, the "U.S. Lead Plaintiff Motions") with the District Court seeking: (i) to consolidate the five U.S. Actions (the "Consolidated U.S. Action"); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013, which the Court

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will consider (along with the motion papers discussed above) in deciding who will serve as lead plaintiff and lead counsel.

Canadian Actions

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

On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario.

On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. This claim names the Company, Barry Welch and Terrence Ronan as defendants (the "Defendants"). The Plaintiffs seeks leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserts common law claims for misrepresentation. The Plaintiffs' allegations focus on among other things, claims the Defendants made materially false and misleading statements and omissions in Atlantic Power's press releases, quarterly and year end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The Plaintiffs seek to certify the statutory and common law claims under the Class Proceedings Act for security holders who purchased and held securities through a proposed class period of November 5, 2012 to February 28, 2013.

On October 4, 2013 the Plaintiffs delivered materials supporting their request for leave to commence an action for statutory misrepresentations and for certification of the statutory and common claims as class proceedings. These materials estimate the damages claimed for statutory misrepresentation at $197.4 million.

A schedule for the Plaintiffs' motions and the action will be set on November 12, 2013.

The Petitioner in the proposed Quebec class action has served and filed a motion to suspend those proceedings until a decision is made on certification of the Ontario action as a class proceeding. This motion will not be contested.

Pursuant to the Private Securities Litigation Reform Act of 1995, all discovery is stayed in the U.S. Actions. Plaintiffs have not yet specified an amount of alleged damages in the U.S. Actions. As noted above, the plaintiffs in the Canadian Action have estimated their alleged statutory damages at $197.4 million. Because both the U.S. and Canadian Actions are in their early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation. Atlantic Power intends to defend vigorously each of the actions.

Other

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. With respect to such other matters arising in the normal course of business, there are no matters pending as of September 30, 2013 that are expected to have a material impact on our financial position or results of operations or have been reserved for as of September 30, 2013.

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Other than as described above, there were no material changes to legal proceedings disclosed in "Item 3. Legal Proceedings" of our Annual Report on Form 10-K for the year ended December 31, 2012.

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, 2012, other than as set forth in "Part II. Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the three months ended March 31, 2013 (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").

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No. |  | Description
--- | --- | ---
| 10.1 |  | Second Amended and Restated Credit Agreement, dated as of August 2, 2013 among the Company, Atlantic Power Generation, Inc. and Atlantic Power Transmission, Inc., the Lenders signatory thereto and Bank of Montreal, as Administrative Agent (incorporated by reference to our Current Report on Form 8-K filed on August 5, 2013)
| 10.2 |  | Addendum to Executive Employment Agreement, dated as of August 30, 2013 (incorporated by reference to our Current Report on Form 8-K filed on September 5, 2013)†
| 12.1 | * | Statement re: Computation of Ratios
| 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.
†
  Executive compensation arrangement.

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SIGNATURES

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

Date: November 7, 2013 |  | Atlantic Power Corporation
|  | By: |  | /s/ TERRENCE RONAN
|  |  |  | Name: |  | Terrence Ronan
|  |  |  | Title: |  | Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

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