Atlantic Power 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 27, 2014	Jun. 28, 2013
Document and Entity Information	'	'	'
Entity Registrant Name	'ATLANTIC POWER CORP	'	'
Entity Central Index Key	'0001419242	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Accelerated Filer	'	'
Entity Public Float	'	'	$0.47
Entity Common Stock, Shares Outstanding	'	120,279,798	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$158.60	$60.20
Restricted cash	114.2	28.6
Accounts receivable	64.3	58.5
Current portion of derivative instruments asset (Note 13)	0.2	9.5
Inventory (Note 5)	16	16.9
Prepayments and other current assets	16.1	13.4
Security deposits	'	19
Assets held for sale (Note 20)	'	351.4
Refundable income taxes	4	4.2
Total current assets	373.4	561.7
Property, plant, and equipment, net (Note 6)	1,813.40	2,055.50
Equity investments in unconsolidated affiliates (Note 4)	394.3	428.7
Power purchase agreements and development intangible assets, net (Note 8)	451.5	524.9
Goodwill (Note 7)	296.3	334.7
Derivative instruments asset (Notes 13)	13	11.1
Other assets	53.1	86.1
Total assets	3,395	4,002.70
Current Liabilities:	'	'
Accounts payable	14	17.8
Accrued interest	17.7	19
Other accrued liabilities	58.8	73.7
Revolving credit facility (Note 10)	'	67
Current portion of long-term debt (Note 10)	216.2	121.2
Current portion of convertible debentures (Note 11)	42.1	'
Current portion of derivative instruments liability (Note 13)	28.5	33
Dividends payable	6.8	11.5
Liabilities associated with assets held for sale (Note 20)	'	189
Other current liabilities	5.3	3.3
Total current liabilities	389.4	535.5
Long-term debt (Note 10)	1,254.80	1,459.10
Convertible debentures (Note 11)	363.1	424.2
Derivative instruments liability (Note 13)	76.1	118.1
Deferred income taxes (Note 14)	111.5	164
Power purchase and fuel supply agreement liabilities, net (Note 8)	38.7	44
Other long-term liabilities (Note 9)	65.4	71.4
Commitments and contingencies (Note 23)	'	'
Total liabilities	2,299	2,816.30
Equity	'	'
Common shares, no par value, unlimited authorized shares; 120,205,813 and 119,446,865 issued and outstanding at December 31, 2013 and December 31, 2012, respectively	1,286.10	1,285.50
Preferred shares issued by a subsidiary company (Note 18)	221.3	221.3
Accumulated other comprehensive income (loss)	-22.4	9.4
Retained deficit	-655.4	-565.2
Total Atlantic Power Corporation shareholders' equity	829.6	951
Noncontrolling interest	266.4	235.4
Total equity	1,096	1,186.40
Total liabilities and equity	$3,395	$4,002.70

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED BALANCE SHEETS	'	'
Common shares, no par value (in dollars per share)	'	'
Common shares, issued shares (in shares)	120,205,813	119,446,865
Common shares, outstanding shares (in shares)	120,205,813	119,446,865

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Project revenue:	'	'	'
Energy sales	$304.20	$217	$43.60
Energy capacity revenue	168.8	154.9	34
Other	78.7	68.5	16.3
Total project revenue	551.7	440.4	93.9
Project expenses:	'	'	'
Fuel	198.7	169.1	37.5
Operations and maintenance	152.4	122.8	20.9
Development	7.2	'	'
Depreciation and amortization	167.1	118	23.6
Total project expenses	525.4	409.9	82
Project other income (expense):	'	'	'
Change in fair value of derivative instruments (Notes 12 and 13)	49.5	-59.3	-14.6
Equity in earnings of unconsolidated affiliates (Note 4)	26.9	15.2	6.4
Gain on sale of equity investments	30.4	0.6	'
Interest expense, net	-34.4	-16.4	-7.3
Impairment of goodwill (Note 7)	-34.9	'	'
Other income, net	0.5	'	'
Total project other income (expense)	38	-59.9	-15.5
Project income (loss)	64.3	-29.4	-3.6
Administrative and other expenses (income):	'	'	'
Administration	35.2	28.3	37.7
Interest, net	104.1	89.8	26
Foreign exchange loss (gain) (Note 13)	-27.4	0.5	13.8
Other income, net	-10.5	-5.7	-0.1
Total administrative and other expenses (income)	101.4	112.9	77.4
Loss from continuing operations before income taxes	-37.1	-142.3	-81
Income tax benefit (Note 14)	-19.5	-28.1	-11.1
Loss from continuing operations	-17.6	-114.2	-69.9
Net income (loss) from discontinued operations, net of tax (Note 20)	-6.2	13.9	34.3
Net loss	-23.8	-100.3	-35.6
Net loss attributable to noncontrolling interests	-3.4	-0.6	-0.5
Net income attributable to preferred shares dividends of a subsidiary company	12.6	13.1	3.3
Net Income (Loss) Available to Common Stockholders, Basic	($33)	($112.80)	($38.40)
Basic and diluted loss per share: (Note 19)	'	'	'
Loss from continuing operations attributable to Atlantic Power Corporation	($0.23)	($1.09)	($0.94)
Income (loss) from discontinued operations, net of tax	($0.05)	$0.12	$0.44
Net loss attributable to Atlantic Power Corporation	($0.28)	($0.97)	($0.50)
Weighted average number of common shares outstanding: (Note 19)	'	'	'
Basic (in shares)	119.9	116.4	77.5
Diluted (in shares)	119.9	116.4	77.5

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	'	'	'
Net loss	($23.80)	($100.30)	($35.60)
Other comprehensive income (loss), net of tax:	'	'	'
Unrealized income (loss) on hedging activities	0.7	-0.9	-2.6
Net amount reclassified to earnings	0.9	0.9	1
Net unrealized gain (loss) on derivatives	1.6	'	-1.6
Defined benefit plan, net of tax	1.4	-1.3	-0.5
Foreign currency translation adjustments	-34.8	15.9	-3.3
Other comprehensive income (loss), net of tax	-31.8	14.6	-5.4
Comprehensive loss	-55.6	-85.7	-41
Less: Comprehensive income attributable to noncontrolling interests	9.2	12.5	2.8
Comprehensive loss attributable to Atlantic Power Corporation	($64.80)	($98.20)	($43.80)

CONSOLIDATED_STATEMENTS_OF_SHA

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (USD $)	Total	Common Shares	Retained Deficit	Accumulated Other Comprehensive Income (loss)	Noncontrolling Interests	Preferred Shares
In Millions, except Share data, unless otherwise specified
Balance at Dec. 31, 2010	$433.40	$626.10	($196.50)	$0.30	$3.50	'
Balance (in shares) at Dec. 31, 2010	'	67,100,000	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'	'	'
Net (loss) income	-35.1	'	-38.4	'	'	3.3
Convertible debenture conversion	26.4	26.4	'	'	'	'
Convertible debenture conversion (in shares)	'	2,100,000	'	'	'	'
Common shares issuance, net of issuance costs	155.4	155.4	'	'	'	'
Common shares issuance, net of issuance costs (in shares)	'	12,700,000	'	'	'	'
Common shares issued for LTIP	2	2	'	'	'	'
Common shares issued for LTIP (in shares)	'	200,000	'	'	'	'
Shares issued in connection with CPILP acquisition	407.4	407.4	'	'	'	'
Shares issued in connection with CPILP acquisition (in shares)	'	31,500,000	'	'	'	'
Preferred shares of a subsidiary company assumed in connection with CPILP acquisition	221.3	'	'	'	'	221.3
Loss from noncontrolling interests	-0.5	'	'	'	-0.5	'
Dividends declared on common shares	-85.7	'	-85.7	'	'	'
Dividends declared on preferred shares of a subsidiary company	-3.3	'	'	'	'	-3.3
Unrealized gain (loss) on hedging activities, net of tax of $1.0 and $0.3 for the year ended 2013 and 2011, respectively	-1.6	'	'	-1.7	'	'
Foreign currency translation adjustments	-3.3	'	'	-3.3	'	'
Defined benefit plan, net of tax of $0.6, $0.8 and $0.3 for the year ended 2013, 2012 and 2011, respectively	-0.5	'	'	-0.5	'	'
Balance at Dec. 31, 2011	1,115.80	1,217.30	-320.6	-5.2	3	221.3
Balance (in shares) at Dec. 31, 2011	'	113,600,000	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'	'	'
Net (loss) income	-99.7	'	-112.8	'	'	13.1
Common shares issuance, net of issuance costs	66.3	66.3	'	'	'	'
Common shares issuance, net of issuance costs (in shares)	'	5,500,000	'	'	'	'
Common shares issued for Equity Incentive Plan	0.1	0.1	'	'	'	'
Common shares issued for LTIP	1.8	1.8	'	'	'	'
Common shares issued for LTIP (in shares)	'	200,000	'	'	'	'
Common shares issued for DRIP (in shares)	'	200,000	'	'	'	'
Noncontrolling interests	233	'	'	'	233	'
Loss from noncontrolling interests	-0.6	'	'	'	-0.6	'
Dividends declared on common shares	-131.8	'	-131.8	'	'	'
Dividends declared on preferred shares of a subsidiary company	-13.1	'	'	'	'	-13.1
Foreign currency translation adjustments	15.9	'	'	15.9	'	'
Defined benefit plan, net of tax of $0.6, $0.8 and $0.3 for the year ended 2013, 2012 and 2011, respectively	-1.3	'	'	-1.3	'	'
Balance at Dec. 31, 2012	1,186.40	1,285.50	-565.2	9.4	235.4	221.3
Balance (in shares) at Dec. 31, 2012	'	119,500,000	'	'	'	'
Increase (decrease) in shareholders' equity	'	'	'	'	'	'
Net (loss) income	-20.4	'	-33	'	'	12.6
Common shares issued for LTIP	0.6	0.6	'	'	'	'
Common shares issued for LTIP (in shares)	'	100,000	'	'	'	'
Common shares issued for DRIP (in shares)	'	600,000	'	'	'	'
Noncontrolling interests	43.3	'	'	'	43.3	'
Loss from noncontrolling interests	-3.4	'	'	'	-3.4	'
Dividends declared on common shares	-57.2	'	-57.2	'	'	'
Dividends paid to noncontrolling interests	-8.9	'	'	'	-8.9	'
Dividends declared on preferred shares of a subsidiary company	-12.6	'	'	'	'	-12.6
Unrealized gain (loss) on hedging activities, net of tax of $1.0 and $0.3 for the year ended 2013 and 2011, respectively	1.6	'	'	1.5	'	'
Foreign currency translation adjustments	-34.8	'	'	-34.7	'	'
Defined benefit plan, net of tax of $0.6, $0.8 and $0.3 for the year ended 2013, 2012 and 2011, respectively	1.4	'	'	1.4	'	'
Balance at Dec. 31, 2013	$1,096	$1,286.10	($655.40)	($22.40)	$266.40	$221.30
Balance (in shares) at Dec. 31, 2013	'	120,200,000	'	'	'	'

CONSOLIDATED_STATEMENTS_OF_SHA1

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY	'	'	'
Unrealized loss on hedging activities, net of tax	$0.60	'	$0.30
Defined benefit plan, net of tax	$1	$0.80	$0.30

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net loss	($23.80)	($100.30)	($35.60)
Adjustments to reconcile to net cash provided by operating activities:	'	'	'
Depreciation and amortization	176.4	157.2	63.6
Loss of discontinued operations	32.8	'	'
(Gain) loss on sale of assets and other charges	-5.1	0.8	'
Long-term incentive plan expense	2.2	2.5	3.2
Asset and goodwill impairment charges	39.7	60.5	1.5
Gain on sale of equity investments	-30.4	-0.6	'
Equity in earnings from unconsolidated affiliates	-26.9	-25.7	-7.9
Distributions from unconsolidated affiliates	40.9	38.4	21.9
Unrealized foreign exchange (gain) loss	-13	19	8.6
Change in fair value of derivative instruments	-60.2	46.7	22.8
Change in deferred income taxes	-27.3	-34.1	-9.9
Change in other operating balances	'	'	'
Accounts receivable	3.4	2.3	-15.6
Inventory	0.8	-6.2	-0.4
Prepayments, refundable income taxes and other assets	51.5	-13.3	2.1
Accounts payable	-8.4	21.1	4.9
Accruals and other liabilities	-0.2	-1.2	-3.3
Cash provided by operating activities	152.4	167.1	55.9
Cash flows provided by (used in) investing activities:	'	'	'
Change in restricted cash	-93.7	-11.6	-5.7
Proceeds from sale of assets and equity investments, net	182.6	27.9	8.5
Cash paid for acquisitions and investments, net of cash acquired	'	-80.5	-591.6
Proceeds from related party	'	'	22.8
Proceeds from treasury grants	103.2	'	'
Biomass development costs	-0.2	-0.5	-0.9
Construction in progress	-38.3	-456.2	-113.1
Purchase of property, plant and equipment	-6.5	-2.9	-2
Cash provided by (used in) investing activities	147.1	-523.8	-682
Cash flows (used in) provided by financing activities:	'	'	'
Proceeds from issuance of long-term debt	'	'	460
Proceeds from issuance of convertible debentures	'	230.6	'
Proceeds from issuance of equity, net of offering costs	-1	66.3	155.4
Proceeds from project-level debt	20.8	291.9	100.8
Repayment of project-level debt	-118.8	-284.8	-21.5
Payments for revolving credit facility borrowings	-67	-60.8	'
Proceeds from revolving credit facility borrowings	'	69.8	58
Deferred financing costs	-2.8	-31.2	-26.4
Equity contribution from noncontrolling interest	44.6	225	'
Dividends paid to common shareholders	-65.1	-131	-81.8
Dividends paid to noncontrolling interests	-18.3	-13.1	-3.2
Cash (used in) provided by financing activities	-207.6	362.7	641.3
Net increase in cash and cash equivalents	91.9	6	15.2
Less cash at discontinued operations	'	-6.5	'
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	45.5
Cash and cash equivalents at end of period	158.6	60.2	60.7
Supplemental cash flow information	'	'	'
Interest paid	130.4	40.2	40.2
Income taxes paid (refunded), net	5.9	1.1	1.1
Accruals for construction in progress	$8.90	$4.10	$4.10

Nature_of_business

Nature of business	12 Months Ended
	Dec. 31, 2013
Nature of business	'
Nature of business	'
	1. Nature of business
	General
	Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of December 31, 2013, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,948 megawatts ("MW") in which our aggregate ownership interest is approximately 2,026 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, which we expect to close in 2014. Our current portfolio consists of interests in twenty-eight 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, Washington. Twenty-two 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.

Summary_of_significant_account

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2013
Summary of significant accounting policies	'
Summary of significant accounting policies	'
	2. Summary of significant accounting policies
	(a)   Principles of consolidation and basis of presentation:
	The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity, through arrangements that do not involve controlling voting interests.
	We apply the standard that requires consolidation of variable interest entities ("VIEs"), for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities' economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We have determined that our equity investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation.
	(b)   Cash and cash equivalents:
	Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of 90 days or less when purchased.
	(c)   Restricted cash:
	Restricted cash represents cash and cash equivalents that are maintained by the projects or corporate to support payments for major maintenance costs and meet project level and corporate contractual debt obligations.
	(d)   Deferred financing costs:
	Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective interest method over the term of the related debt which range from 5 to 28 years. The net carrying amount of deferred financing costs recorded in other assets on the consolidated balance sheets was $41.7 million and $47.2 million at December 31, 2013 and 2012, respectively. Amortization expense for the years ended December 31, 2013, 2012, and 2011 was $8.0 million, $4.4 million, and $1.3 million, respectively.
	(e)   Inventory:
	Inventory represents small parts and other consumables and fuel, the majority of which is consumed by our projects in provision of their services, and are valued at the lower of cost or net realizable value. Cost includes the purchase price, transportation costs and other costs to bring the inventories to their present location and condition. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs.
	(f)    Property, plant and equipment:
	Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset, up to 45 years. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in the consolidated statements of operations.
	(g)   Project development costs and capitalized interest:
	Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, obtaining a PPA.
	Interest incurred on funds borrowed to finance capital projects is capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2013, 2012, and 2011 was $1.9 million, $17.0 million, and $3.0 million, respectively.
	When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
	(h)   Other intangible assets:
	Other intangible assets include PPAs and fuel supply agreements at our projects. PPAs are valued at the time of acquisition based on the contract prices under the PPAs compared to projected market prices. Fuel supply agreements are valued at the time of acquisition based on the contract prices under the fuel supply agreement compared to projected market prices. The balances are presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement.
	(i)    Investments accounted for by the equity method:
	We make investments in entities that own power producing assets with the objective of generating accretive cash flow that is available to be distributed to our shareholders. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents us from exercising a controlling influence over the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with 50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships and limited liability companies with greater than 5% ownership because our influence over the investment's operating and financial policies is considered to be more than minor.
	Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings of unconsolidated affiliates. The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the affiliates' power producing assets and are classified as cash flows from operating activities in the consolidated statements of cash flows. We record the return of our investments in equity investees as cash flows from investing activities. Cash flows from equity investees are considered a return of capital when distributions are generated from proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets.
	(j)    Impairment of long-lived assets, non-amortizing intangible assets and equity method investments:
	Long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds its fair value.
	Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. We also review a project for impairment and perform a two-step test at the earlier of executing a new PPA (or other arrangement) or six months prior to the expiration of an existing PPA. Factors such as the business climate, including current energy and market conditions, environmental regulation, the condition of assets, and the ability to secure new PPAs are considered when evaluating long-lived assets for impairment. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment or, where applicable, estimated sales proceeds that are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value.
	(k)   Goodwill:
	Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the business combination.
	Goodwill is not amortized and is tested for impairment, annually in the fourth quarter, or more frequently if events or changes in circumstances indicate that the asset might be impaired. In September 2011, the Financial Accounting Standards Board ("FASB") issued ASU 2011-08 "Intangibles—Goodwill and Other." This guidance on testing goodwill provides the option to first perform a qualitative assessment ("step zero") to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If we determine that this is the case, we are required to perform a two-step goodwill impairment test, as described below, to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized for that reporting unit (if any). If we determine that the fair value of a reporting unit is not less than its carrying amount, the two-step goodwill impairment test is not required.
	In our test, we first perform step zero to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (i.e. more than 50%) that the fair value of a reporting unit 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 the qualitative assessment determines that an impairment is more likely than not, then we perform a two-step quantitative impairment test. In the first step of the quantitative analysis, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired and the second step of the impairment test is unnecessary.
	The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit's goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination, using the fair value of the reporting unit as if it were the purchase price. When the carrying amount of reporting unit goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess and is recorded in the consolidated statements of operations.
	(l)    Discontinued operations:
	Long-lived assets or disposal groups are classified as discontinued operations when all of the required criteria are met. Criteria include, among others, existence of a qualified plan to dispose of an asset or disposal group, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management. In addition, upon completion of the transaction, the operations and cash flows of the disposal group must be eliminated from our ongoing operations, and the disposal group must not have any significant continuing involvement with us. Discontinued operations are reported at the lower of the asset's carrying amount or fair value less cost to sell.
	(m)  Derivative financial instruments:
	We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a major production cost. We do not enter into derivative financial instruments for trading or speculative purposes. Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales in the ordinary course of conducting business. This exception applies when we have the ability to, and it is probable that we will deliver or take delivery of the underlying physical commodity.
	We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Derivatives accounted for as hedges are recorded at fair value in the balance sheet. Unrealized gains or losses on derivatives designated as a hedge are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings.
	Derivative financial instruments not designated as a hedge are measured at fair value with changes in fair value recorded in the consolidated statements of operations. The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument:
	Derivative financial instrument	Classification of changes in fair value		Classification of cash settlements
	Natural gas swaps	Changes in fair value of derivative instrument		Fuel expense
	Gas purchase agreements	Changes in fair value of derivative instrument		Fuel expense
	Interest rate swaps	Changes in fair value of derivative instrument		Interest expense
	Foreign currency forward contract	Foreign exchange (gain) loss		Foreign exchange (gain) loss
	(n)   Income taxes:
	Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 14 for more information.
	(o)   Revenue recognition:
	We recognize energy sales revenue on a gross basis when electricity and steam are delivered under the terms of the related contracts. PPAs, steam purchase arrangements and energy services agreements are long-term contracts to sell power and steam on a predetermined basis.
	Energy—Energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in our consolidated statements of operations.
	Capacity—Capacity payments under the PPAs are recognized as the lesser of (1) the amount billable under the PPA or (2) an amount determined by the kilowatt hours made available during the period multiplied by the estimated average revenue per kilowatt hour over the term of the PPA.
	(p)   Power purchase arrangements containing a lease:
	We have entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the project's property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.
	Finance income related to leases or arrangements accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income (loss) over the lease term.
	For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of energy revenue. When energy is delivered, we recognize lease income in energy revenue.
	(q)   Foreign currency translation and transaction gains and losses:
	The local currency is the functional currency of our U.S. and Canadian projects. Our reporting currency is the U.S. dollar. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of our statements of operations for the period, but are accumulated and reported as a separate component of shareholders' equity until sale of the net investment in the project takes place. Foreign currency transaction gains or losses are reported within foreign exchange (gain) loss in our statements of operations.
	(r)   Equity compensation plans:
	The officers and certain other employees are eligible to participate in the Long-Term Incentive Plan ("LTIP"). Some of the notional units that vest are based, in part, on certain financial performance metrics and the total shareholder return of Atlantic Power compared to a group of peer companies. In addition, vesting of certain notional units for officers of Atlantic Power occurs on a three-year cliff basis as opposed to ratable vesting over three years for non-officers. During April 2012, the Compensation Committee of the Board approved certain changes to the award process and vesting criteria of the LTIP, and on April 11, 2013, the Board adopted the Fifth Amended and Restated Atlantic Power Holdings, Inc. LTIP (the "Fifth Amended and Restated LTIP"), which reflected such changes. Awards to senior officers under the Fifth Amended and Restated LTIP are made annually based on the performance over the applicable fiscal year and will vest as to one third over each of the three years following the year of the award. Notional shares granted prior to the amendment are still subject to three-year cliff vesting.
	Vested notional units are expected to be redeemed one-third in cash and two-thirds in shares of our common stock. Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date or if we do not meet certain ongoing cash flow performance targets.
	For awards that are subject to a performance-based vesting condition, the final number of notional units for officers that will vest, if any, at the end of the three-year vesting period is based on our achievement of certain financial performance metrics and meeting target levels of relative total shareholder return, which is the change in the value of an investment in our common stock, including reinvestment of dividends, compared to that of a peer group of companies during the performance period. The total number of notional units vesting will range from zero up to a maximum 150% of the number of notional units in the executives' accounts on the vesting date for that award, depending on the level of achievement of relative total shareholder return during the measurement period.
	Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. The fair value of awards granted under the LTIP with market vesting conditions is based upon a Monte Carlo simulation model on the grant date. Compensation expense is recognized regardless of the relative total shareholder return performance, provided that the LTIP participant remains employed by Atlantic Power.
	(s)   Asset retirement obligations:
	The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss.
	(t)    Pensions:
	We offer pension benefits to certain employees through a defined benefit pension plan. We recognize the funded status of our defined benefit plan in the consolidated balance sheet in other long-term liabilities and record an offset to other comprehensive income (loss). In addition, we also recognize on an after-tax basis, as a component of other comprehensive income (loss), gains and losses as well as all prior service costs that have not been included as part of our net periodic benefit cost. The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Our actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of our pension obligation or expense recorded.
(u)   Business combinations:
We account for our business combinations in accordance with the acquisition method of accounting, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
(v)   Concentration of credit risk:
The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to the credit worthiness and payment history of our customers. See Note 21, Segment and geographic information, for a further discussion of customer concentrations.
(w)  Use of estimates:
The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and the allocation of taxable income and losses, tax credits and cash distributions using the hypothetical liquidation book value ("HLBV") method. 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. 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.
(x)   Federal grants:
Certain projects are eligible to receive grants and similar government incentives for the construction of renewable energy facilities. Proceeds from these grants reduce the basis of the corresponding asset balance when the cash is received.
(y)   Allocation of net income or losses to certain investors using HLBV:
For consolidated investments with flip structures that allocate taxable income and losses, tax credits and cash distributions under allocation provisions of agreements with third-party investors, net income or loss is allocated to third-party investors for accounting purposes using the hypothetical liquidation book value method. HLBV is a balance sheet oriented approach that calculates the change in the claims of each partner on the net assets of the investment at the beginning and end of each period. Each partner's claim is equal to the amount each party would receive or pay if the net assets of the investment were to liquidate at book value and the resulting cash was then distributed to investors in accordance with their respective liquidation preferences. We report the net income or loss attributable to the third-party investors as income (loss) attributable to noncontrolling interests in the consolidated statements of operations.
(z)   Recently issued accounting standards:
Adopted
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.
The changes in accumulated other comprehensive income (loss) by component were as follows:
	Year Ended December 31,
	2013			2012			2011
Foreign currency translation
Balance at beginning of period	$	12.6		$	(3.3	)	$	—
Other comprehensive income (loss):
Foreign currency translation adjustments(1)		(34.8	)		15.9			(3.3	)
Balance at end of period	$	(22.2	)	$	12.6		$	(3.3	)
Pension
Balance at beginning of period	$	(1.8	)	$	(0.5	)	$	—
Other comprehensive income (loss):
Unrecognized net actuarial gain (loss)		2.4			(2.1	)		(0.8	)
Tax benefit (expense)		(0.7	)		0.8			0.3
Total Other comprehensive income (loss) before reclassifications, net of tax		1.7			(1.3	)		(0.5	)
Amortization of net actuarial gain(2)		(0.4	)		—			—
Tax benefit (expense)(5)		0.1			—			—
Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		(0.3	)		—			—
Total Other comprehensive income (loss)		1.4			(1.3	)		(0.5	)
Balance at end of period	$	(0.4	)	$	(1.8	)	$	(0.5	)
Cash flow hedges
Balance at beginning of period	$	(1.4	)	$	(1.4	)	$	0.2
Other comprehensive income (loss):
Net change from periodic revaluations		1.2			(1.5	)		(4.4	)
Tax benefit (expense)		(0.5	)		0.6			1.8
Total Other comprehensive income (loss) before reclassifications, net of tax		0.7			(0.9	)		(2.6	)
Net amount reclassified to earnings:
Interest rate swaps(3)		1.7			1.9			2.3
Fuel commodity swaps(4)		(0.2	)		(0.4	)		(0.7	)
Sub-total		1.5			1.5			1.6
Tax benefit(5)		(0.6	)		(0.6	)		(0.6	)
Total amount reclassified from Accumulated other comprehensive loss, net of tax(6)		0.9			0.9			1
Total Other comprehensive income (loss)		1.6			—			(1.6	)
Balance at end of period	$	0.2		$	(1.4	)	$	(1.4	)
-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 Administration on the accompanying Consolidated Statements of Operations.
-3
This amount was included in Interest, net on the accompanying Consolidated Statements of Operations.
-4
These amounts were included in Fuel on the accompanying Consolidated Statements of Operations.
-5
These amounts were included in Income tax expense (benefit) on the accompanying Consolidated Statements of Operations.
-6
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 Consolidated Statements of Operations in the line items indicated in footnotes 2 through 5.
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.
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, 2012, we adopted changes issued by the FASB to conform existing guidance regarding fair value measurement and disclosure between 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 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 our consolidated financial statements.
On January 1, 2012, we adopted changes issued by the FASB to the presentation of comprehensive income (loss). These changes give an entity the option to present the total of comprehensive income (loss), the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income (loss) or in two separate but consecutive statements; the option to present components of other comprehensive income (loss) as part of the statement of changes in shareholders' equity was eliminated. The items that must be reported in other comprehensive income (loss) or when an item of other comprehensive income (loss) must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. We elected to present the two-statement option. Other than the change in presentation, the adoption of these changes had no impact on our consolidated financial statements.
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 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. 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.
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.

Acquisitions_and_divestments

Acquisitions and divestments	12 Months Ended
	Dec. 31, 2013
Acquisitions and divestments	'
Acquisitions and divestments	'
	3. Acquisitions and divestments
	2012 Acquisitions
	(a)   Ridgeline
	On November 5, 2012 we entered into a purchase and sale agreement to acquire a 100% ownership interest in Ridgeline for approximately $81.3 million. Ridgeline develops, constructs and operates wind and solar energy projects across the United States. As a result of the acquisition, we increased our ownership in Rockland Wind Farm, LLC. ("Rockland") from a 30% to a 50% managing member interest (which is 100% consolidated) and our net generation capacity increased from 24 to 40 MW. We also acquired a 12.5% equity ownership in Goshen North, a 124.5 MW (16 MW, net) wind project operating in Idaho. Additionally, we purchased a 100% ownership interest in Meadow Creek, a 119.7 MW wind project operating in Idaho, which completed construction and became operational on December 22, 2012. The acquisition of Ridgeline provides a pipeline of potential wind and solar projects in various phases of development.
	We closed on this transaction on December 31, 2012 and financed the acquisition through the issuance of Cdn$100 million (approximately Cdn$95 million after underwriting and transaction costs) aggregate principal amount of series D extendible convertible unsecured subordinated debentures (the "December 2012 Debentures").
	Our acquisition of Ridgeline was accounted for under the acquisition method of accounting as of the transaction closing date. The final purchase price allocation for the business combination is as follows:
	Fair value of consideration transferred:
	Cash	$	81.3
	Other items to be allocated to identifiable assets acquired and liabilities assumed:
	Fair value of our investment in Rockland at the acquisition date		12.1
	Loss recognized on the step acquisition		(7.4	)
	Total purchase price	$	86
	Final purchase price allocation
	Cash	$	1
	Working capital		(8.1	)
	Property, plant, and equipment		373.9
	Deferred tax asset		9.6
	Other long-term assets		36
	Long-term debt		(295.5	)
	Interest rate swaps		(21.6	)
	Other long-term liabilities		(1.3	)
	Minority interest		(8.0	)
	Total identifiable net assets	$	86
	The fair values of the assets acquired and liabilities assumed were estimated by applying an income approach using the discounted cash flow method. These measurements were based on significant inputs not observable in the market and thus represent a level 3 fair value measurement. The primary considerations and assumptions that affected the discounted cash flows included the operational characteristics and financial forecasts of acquired facilities, remaining useful lives and discount rates based on the weighted average cost of capital ("WAAC") adjusted for the risk and characteristics of each plant.
	During the fourth quarter of 2013, we adjusted the fair value of the net deferred taxes recorded in the preliminary purchase price allocation. The adjustment was based on the final determination of deferred taxes on net operating loss carryforwards and other tax attributes that were acquired as part of the Ridgeline acquisition. As a result, the opening deferred tax liability of $14.2 million was adjusted to a deferred tax asset of $9.6 million with a corresponding reduction to property, plant and equipment of $23.9 million. The Ridgeline purchase price allocation is final at December 31, 2013.
	(b)   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 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 December 31, 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.
	The acquisition of Canadian Hills was accounted for as an asset purchase and is consolidated in our consolidated balance sheet at December 31, 2013. We own 99% of the project and consolidate it in our consolidated financial statements. Income attributable to noncontrolling interests is allocated utilizing HLBV.
	2011 Acquisitions
	(a)   Capital Power Income L.P.
	On November 5, 2011, we completed the acquisition of all of the outstanding limited partnership units of Capital Power Income, LP (renamed Atlantic Power Limited Partnership on February 1, 2012, the "Partnership") pursuant to the terms and conditions of an arrangement agreement, dated June 20, 2011, as amended by Amendment No. 1, dated July 15, 2011 (the "Arrangement Agreement"), by and among us, the Partnership, CPI Income Services, Ltd., the general partner of the Partnership and CPI Investments, Inc., a unitholder of the Partnership that was then owned by EPCOR Utilities Inc. and Capital Power Corporation. The transactions contemplated by the Arrangement Agreement were effected through a court-approved plan of arrangement under the Canada Business Corporations Act (the "Plan of Arrangement"). The Plan of Arrangement was approved by the unitholders of the Partnership, and the issuance of our common shares to the Partnership unitholders pursuant to the Plan of Arrangement was approved by our shareholders, at respective special meetings held on November 1, 2011. A Final Order approving the Plan of Arrangement was granted by the Court of Queen's Bench of Alberta on November 1, 2011. Pursuant to the Plan of Arrangement, the Partnership sold its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power Corporation, for approximately Cdn$121.4 million which equates to approximately Cdn$2.15 per unit of the Partnership. In addition, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power Corporation and the Partnership and certain of its subsidiaries were terminated in consideration of a payment of Cdn$10.0 million. Atlantic Power and its subsidiaries assumed the management of the Partnership upon closing and entered into a transitional services agreement with Capital Power Corporation for a term of six to twelve months to facilitate and support the integration of the Partnership into Atlantic Power.
	The acquisition expanded and diversified our asset portfolio to include projects in Canada and regions of the United States where we did not have a presence. At the time of the acquisition of the Partnership, our average PPA term increased from 8.8 years to 9.1 years and enhanced the credit quality of our portfolio of off takers.
	Pursuant to the Plan of Arrangement, we directly and indirectly acquired each outstanding limited partnership unit of the Partnership in exchange for Cdn$19.40 in cash ("Cash Consideration") or 1.3 Atlantic Power common shares ("Share Consideration") in accordance with elections and deemed elections in accordance with the Plan of Arrangement.
	As a result of the elections made by the Partnership unitholders and pro-ration in accordance with the Plan of Arrangement, those unitholders who elected to receive Cash Consideration received in exchange for each limited partnership unit of the Partnership (i) cash equal to approximately 73% of the Cash Consideration and (ii) Share Consideration in respect of the remaining approximately 27% of the consideration payable for the unit. Any limited partnership units of the Partnership not exchanged for cash consideration in accordance with the Plan of Arrangement were exchanged for Share Consideration.
	At closing, the consideration paid to acquire the Partnership totaled $1.0 billion, consisting of $601.8 million paid in cash and $407.4 million in shares of our common shares (31.5 million shares issued) less cash acquired of $22.7 million.
	Our acquisition of the Partnership is accounted for under the acquisition method of accounting as of the transaction closing date. The final purchase price allocation for the business combination is as follows:
	Fair value of consideration transferred:
	Cash	$	601.8
	Equity		407.4
	Total purchase price	$	1,009.20
	Final purchase price allocation
	Working capital	$	38
	Property, plant, and equipment		1,024.00
	Intangibles		528.5
	Other long-term assets		224.3
	Long-term debt		(621.6	)
	Other long-term liabilities		(129.3	)
	Deferred tax liability		(164.5	)
	Total identifiable net assets		899.4
	Preferred shares		(221.3	)
	Goodwill		331.1
	Total purchase price		1,009.20
	Less cash acquired		(22.7	)
	Cash paid, net of cash acquired	$	986.5
	The purchase price was computed using the Partnership's outstanding units as of June 30, 2011, adjusted for the exchange ratio at November 5, 2011. The purchase price reflects the market value of our common shares issued in connection with the transaction based on the closing price of the Partnership's units on the TSX on November 5, 2011. The goodwill was attributable to the expansion of our asset portfolio to include projects in Canada and regions of the United States where we did not have a presence. It is not expected to be deductible for tax purposes.
	The fair values of the assets acquired and liabilities assumed were estimated by applying an income approach using the discounted cash flow method. These measurements were based on significant inputs not observable in the market and thus represent a level 3 fair value measurement. The primary considerations and assumptions that affected the discounted cash flows included the operational characteristics and financial forecasts of acquired facilities, remaining useful lives and discount rates based on the WACC on a merchant basis. The WACCs were based on a set of comparable companies as well as existing yields for debt and equity as of the acquisition date.
	The Partnership contributed revenues of $73.8 million and a loss of less than $0.1 million to our consolidated statements of operations for the period from November 5, 2011 to December 31, 2011. The following unaudited pro-forma consolidated results of operations for years ended December 31, 2011 and 2010, assume the Partnership acquisition occurred as of January 1 of each year. The pro forma results of operations are presented for informational purposes only and are not indicative of the results of operations that would have been achieved if the acquisition had taken place on January 1, 2011 and January 1, 2010 or of results that may occur in the future:
		Unaudited
		Years ended
		December 31,
		2011			2010
	Total project revenue	$	694.2		$	670
Net loss attributable to Atlantic Power Corporation		(95.8	)		(2.5	)
Net loss per share attributable to Atlantic Power Corporation shareholders:
Basic	$	(0.85	)	$	(0.02	)
Diluted	$	(0.85	)	$	(0.02	)
(b)   Rockland
On December 28, 2011, we purchased a 30% interest for $12.5 million in Rockland, an 80 MW wind farm near American Falls, Idaho, that began operations in early December 2011. Rockland sells power under a 25-year power purchase agreement with Idaho Power. Rockland was accounted for under the equity method of accounting through December 30, 2012. On December 31, 2012, we finalized our purchase of an additional 20% interest in Rockland through our acquisition of Ridgeline and consolidated the project. See Note 3(a) for further discussion of the Ridgeline acquisition.
2013 Divestments
(a)   Rollcast
On November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As consideration for the sale, we were assigned asset management contracts valued at $0.5 million for the Cadillac and Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In return, we paid $0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was provided by us to Rollcast to fund working capital during 2013. We recorded a $1.0 million gain on sale which is recorded in other income, net in the consolidated statements of operations for the year ended December 31, 2013. Rollcast's net loss is recorded as loss from discontinued operations in the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011.
(b)   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 gain on sale of equity investments in the consolidated statements of operations for the year ended December 31, 2013. We received net cash proceeds for our ownership interest of approximately $34.7 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.
(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. ("Pasco") projects (collectively, the "Florida Projects") for approximately $140.0 million, with working capital adjustments. The sale closed on April 12, 2013 and we received net cash proceeds of approximately $117.0 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 $92.0 million received at closing and cash distributions from the Florida Projects of approximately $25.0 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 as a component of discontinued operations in the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011. See Note 20, Assets held for sale, for further information.
(d)   Path 15
On March 11, 2013, we entered into a purchase and sales agreement with 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 sheets at December 31, 2012 and as a component of discontinued operations in the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011. See Note 20, Assets held for sale, for further information.
(e)   Delta-Person
On December 7, 2012, we entered into a purchase and sale agreement for the sale of our 40% interest in Delta-Person. We will receive approximately $9.0 million in proceeds and the transaction is expected to close in 2014.
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 sale, we recorded an impairment charge in 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 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.
2011 Divestments
(a)   Onondaga Renewables
In the fourth quarter of 2011, the partners of Onondaga Renewables initiated a plan to sell their interests in the project. We determined that the carrying value of the Onondaga Renewables project was impaired and recorded a pre-tax long-lived asset impairment of $1.5 million. Our estimate of the fair market value of our 50% investment in the Onondaga Renewables project was determined based on quoted market prices for the remaining land and equipment. The Onondaga Renewables project is accounted for under the equity method of accounting and the impairment charge is included in equity earnings from unconsolidated affiliates in the consolidated statements of operations.
(b)   Topsham
On February 28, 2011, we entered into a purchase and sale agreement with an affiliate of ArcLight for the purchase of our lessor interest in the project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million, resulting in no gain or loss on the sale.

Equity_method_investments_in_u

Equity method investments in unconsolidated affiliates	12 Months Ended
	Dec. 31, 2013
Equity method investments in unconsolidated affiliates	'
Equity method investments in unconsolidated affiliates	'
	4. Equity method investments in unconsolidated affiliates
	The following tables summarize our equity method investments:
					Carrying value as of
		Percentage of			December 31.
		Ownership as of
	Entity name	December 31, 2013			2013			2012
	Frederickson		50	%	$	153.9		$	167.7
	Orlando Cogen, LP		50	%		14.3			19.9
	Onondaga Rewables, LLC		50	%		—			0.2
	Koma Kulshan Associates		49.8	%		5.8			6.4
	Chambers Cogen, LP		40	%		153.7			154.3
	Delta-Person, LP		40	%		—			—
	Idaho Wind Partners 1, LLC		27.6	%		33.2			34.7
	Selkirk Cogen Partners, LP		18.5	%		24.4			33.7
	Goshen North		12.5	%		9			9
	Gregory Power Partners, LP		—			—			2.8
	Total				$	394.3		$	428.7
	Equity (deficit) in earnings (loss) of equity method investments was as follows:
		Year Ended December 31,
	Entity name	2013			2012			2011
	Chambers Cogen, LP	$	9.6		$	17.1		$	7.7
	Orlando Cogen, LP		3.3			3.2			0.9
	Koma Kulshan Associates		0.3			0.5			0.5
	Frederickson		2.1			0.9			0.4
	Idaho Wind Partners 1, LLC		(0.3	)		(0.2	)		(1.6	)
	Selkirk Cogen Partners, LP		8.7			7.6			(0.4	)
	Goshen North		1.4			—			—
	Gregory Power Partners, LP(1)		1.6			(0.7	)		0.5
	Onondaga Rewables, LLC		(0.3	)		(0.4	)		(1.8	)
	Rockland Wind Farm(2)		—			(8.0	)		—
	Other		0.5			(4.8	)		0.2
	Total		26.9			15.2			6.4
	Distributions from equity method investments		(40.9	)		(38.4	)		(21.9	)
	Deficit in earnings (loss) of equity method investments, net of distributions	$	(14.0	)	$	(23.2	)	$	(15.5	)
	-1
	We sold Gregory in August 2013, resulting in a gain $30.4 million, which is recorded in gain on sale of equity investments in the consolidated statements of operations for the year ended December 31, 2013.
	-2
	Due to an ownership change from 30% to 50% as part of the Ridgeline acquisition during the fourth quarter of 2012, Rockland Wind Farm was consolidated as of December 31, 2012.
	The following summarizes the financial position at December 31, 2013, 2012 and 2011, and operating results for the years ended December 31, 2013, 2012 and 2011, respectively, for our proportional ownership interest in equity method investments:
		2013			2012			2011
	Assets
	Current assets
	Chambers Cogen, LP	$	11.8		$	16.1		$	9.9
	Selkirk Cogen Partners, LP		12.9			12.9			15.9
	Other		24.6			32			22.3
	Non-current assets
	Chambers Cogen, LP		224			235.2			245.8
	Selkirk Cogen Partners, LP		14.1			26			47.7
	Other		286.6			322.3			359.1
		$	574		$	644.5		$	700.7
	Liabilities
	Current liabilities
	Chambers Cogen, LP	$	4.4		$	15.2		$	16
	Selkirk Cogen Partners, LP		2.3			4.8			14.7
	Other		13.9			16.4			19.1
	Non-current liabilities
	Chambers Cogen, LP		77.7			81.8			96
	Selkirk Cogen Partners, LP		0.3			0.3			1.5
	Other		81.1			97.3			79
		$	179.7		$	215.8		$	226.3
	Operating results	2013			2012			2011
	Revenue
	Chambers Cogen, LP	$	52.7		$	58.1		$	49.3
Selkirk Cogen Partners, LP		50.5			48.7			54.6
Other		101.2			109.8			91.8
		204.4			216.6			195.7
Project expenses
Chambers Cogen, LP		40.6			39.1			39.4
Selkirk Cogen Partners, LP		40.3			42.4			49.6
Other		88.9			92.7			85.4
		169.8			174.2			174.4
Project other income (expense)
Chambers Cogen, LP		(2.5	)		(1.9	)		(2.2	)
Selkirk Cogen Partners, LP		(1.5	)		1.3			(5.4	)
Other		(3.7	)		(26.6	)		(7.3	)
		(7.7	)		(27.2	)		(14.9	)
Project income (loss)
Chambers Cogen, LP	$	9.6		$	17.1		$	7.7
Selkirk Cogen Partners, LP		8.7			7.6			(0.4	)
Other		8.6			(9.5	)		(0.9	)
		26.9			15.2			6.4

Inventory

Inventory	12 Months Ended
	Dec. 31, 2013
Inventory	'
Inventory	'
	5. Inventory
	Inventory consists of the following:
		December 31,
		2013		2012
	Parts and other consumables	$	11.3	$	8.6
	Fuel		4.7		8.3
	Total inventory	$	16	$	16.9

Property_plant_and_equipment

Property, plant and equipment	12 Months Ended
	Dec. 31, 2013
Property, plant and equipment	'
Property, plant and equipment	'
	6. Property, plant and equipment
		December 31,			December 31,			Depreciable
		2013			2012			Lives
	Land	$	5.9		$	7.3
	Office equipment, machinery and other		3.3			2.9		3 - 10 years
	Leasehold improvements		0.4			0.4		7 - 15 years
	Asset retirement obligation		34.8			35.8		1 - 42 years
	Plant in service		1,938.40			1,895.00		1 - 45 years
	Construction in progress		5.7			193.7
			1,988.50			2,135.10
	Less accumulated depreciation		(175.1	)		(79.6	)
		$	1,813.40		$	2,055.50
	Depreciation expense of $106.0 million, $58.6 million and $13.2 million was recorded for the years ended December 31, 2013, 2012 and 2011, respectively.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2013
Goodwill	'
Goodwill	'
	7. Goodwill
	Our goodwill balance was $296.3 million and $334.7 million as of December 31, 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 one of the goodwill impairment test, we performed a step two test to quantify the amount, if any, of non-cash impairment to goodwill to record.
	As a result of the event-driven goodwill assessment completed in the third quarter of 2013, it was determined that goodwill was impaired at the Kenilworth reporting unit (East segment) and the Naval reporting units (West 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 as compared to the assumptions used at the time of the acquisition in November 2011. When performing our step two 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 energy prices currently forecasted to be in effect 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 unit's 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 test goodwill for impairment and to write-off the capitalized development costs was based on the reduced expectation of the Greenway project being further developed. Rollcast was sold in November 2013 and is classified as a component of discontinued operations for the years ended December 31, 2013, 2012 and 2011.
	We updated our goodwill impairment analysis as of November 30, 2013 which resulted in no additional impairments.
	Under the two-step quantitative impairment tests performed, the evaluation of impairment involved comparing the current fair value of each reporting unit to its carrying value, including goodwill. For step one of the quantitative tests, we determined 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.
	The valuation of goodwill for the second step of the goodwill impairment analysis is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management's own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities.
	The following table details the changes in the carrying amount of goodwill by operating segment:
		East			West			Wind		Un-allocated			Total
										corporate
	Balance at December 31, 2011	$	138.6		$	201.5		$	—	$	3.5		$	343.6
	Reclass to assets held for sale		—			(8.9	)		—		—			(8.9	)
	Balance at December 31, 2012		138.6			192.6			—		3.5			334.7
	Impairment of goodwill		(30.8	)		(4.1	)		—		(3.5	)		(38.4	)
	Balance at December 31, 2013	$	107.8		$	188.5		$	—	$	—		$	296.3

Power_purchase_agreements_and_

Power purchase agreements and other intangible assets and liabilities	12 Months Ended
	Dec. 31, 2013
Power purchase agreements and other intangible assets and liabilities.	'
Power purchase agreements and other intangible assets and liabilities	'
	8. Power purchase agreements and other intangible assets and liabilities
	Other intangible assets and liabilities include power purchase agreements, fuel supply agreements and development costs.
	The following tables summarize the components of our intangible assets and other liabilities subject to amortization for the years ended December 31, 2013 and 2012:
		Other Intangible Assets, Net
		Power			Development			Total
		Purchase			Costs
		Agreements
	Gross balances, December 31, 2013	$	597.4		$	4.8		$	602.2
	Less: accumulated amortization		(139.8	)		(0.3	)		(140.1	)
	Foreign currency translation adjustment		(10.6	)		—			(10.6	)
	Net carrying amount, December 31, 2013	$	447		$	4.5		$	451.5
		Other Intangible Assets, Net
		Power			Development			Total
		Purchase			Costs
		Agreements
	Gross balances, December 31, 2012	$	590.9		$	6.2		$	597.1
	Less: accumulated amortization		(76.9	)		—			(76.9	)
	Foreign currency translation adjustment		4.7			—			4.7
	Net carrying amount, December 31, 2012	$	518.7		$	6.2		$	524.9
		Power Purchase and Fuel Supply
		Agreement Liabilities, Net
		Power			Fuel			Total
		Purchase			Supply
		Agreements			Agreements
	Gross balances, December 31, 2013	$	(35.9	)	$	(12.6	)	$	(48.5	)
	Less: accumulated amortization		5.3			2.5			7.8
	Foreign currency translation adjustment		2			—			2
	Net carrying amount, December 31, 2013	$	(28.6	)	$	(10.1	)	$	(38.7	)
		Power Purchase and Fuel Supply
		Agreement Liabilities, Net
		Power			Fuel			Total
		Purchase			Supply
		Agreements			Agreements
	Gross balances, December 31, 2012	$	(35.3	)	$	(12.6	)	$	(47.9	)
	Less: accumulated amortization		2.9			1.6			4.5
	Foreign currency translation adjustment		(0.6	)		—			(0.6	)
	Net carrying amount, December 31, 2012	$	(33.0	)	$	(11.0	)	$	(44.0	)
	The following table presents amortization expense of intangible assets for the years ended December 31, 2013, 2012 and 2011:
		2013			2012			2011
	Power purchase agreements	$	60.8		$	59.5		$	11.6
	Fuel supply agreements		(1.2	)		(1.2	)		(1.4	)
	Total amortization expense	$	59.6		$	58.3		$	10.2
	The following table presents estimated future amortization expense for the next five years related to power purchase agreements and fuel supply agreements:
	Year Ended December 31,	Power Purchase			Fuel Supply
		Agreements			Agreements
	2014	$	58.4		$	(1.2	)
	2015		55			(1.2	)
	2016		55			(1.2	)
	2017		55.1			(1.2	)
	2018		47.3			(1.2	)
	The following table presents the weighted average remaining amortization period related to our intangible assets as of December 31, 2013:
	As of December 31, 2013	Power Purchase			Fuel Supply
		Agreements			Agreements
	(in years)
	Weighted average remaining amortization period		9			9

Other_longterm_liabilities

Other long-term liabilities	12 Months Ended
	Dec. 31, 2013
Other long-term liabilities	'
Other long-term liabilities	'
	9. Other long-term liabilities
	Other long-term liabilities consist of the following:
		2013			2012
	Asset retirement obligations	$	57.7		$	57.8
	Net pension liability		0.8			4.8
	Deferred revenue		4			4.9
	Other		2.9			3.9
		$	65.4		$	71.4
	We assumed asset retirement obligations ("ARO") in our acquisition of the Partnership. During 2012, we also recorded asset retirement obligations related to the Canadian Hills project. We recorded these retirement obligations as we are legally required to remove these facilities at the end of their useful lives and restore the sites to their original condition. The following table represents the fair value of ARO at the date of acquisition along with the additions, reductions and accretion related to our ARO for the year ended December 31, 2013:
		2013
	Asset retirement obligations beginning of year	$	57.8
	Accretion of asset retirement obligations		1.6
	Translation adjustments		(1.7	)
	Asset retirement obligations, end of year	$	57.7

Longterm_debt

Long-term debt	12 Months Ended
	Dec. 31, 2013
Long-term debt	'
Long-term debt	'
	10. Long-term debt
	Long-term debt consists of the following:
		December 31,			December 31,			Interest Rate
		2013			2012
	Recourse Debt:
	Senior unsecured notes, due 2018	$	460		$	460		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)		197.4			211.1		6.00%
	Senior unsecured notes, due July 2014(3)		190			190		5.90%
	Series A senior unsecured notes, due August 2015(3)		150			150		5.90%
	Series B senior unsecured notes, due August 2017(3)		75			75		6.00%
	Non-Recourse Debt:
	Epsilon Power Partners term facility, due 2019		30.5			33.5		7.40%
	Cadillac term loan, due 2025		35.4			37.8		6.0% - 8.0%
	Piedmont construction loan, due 2014(1)		76.6			127.4		Libor plus 3.5%
	Meadow Creek term loan, due 2024(2)		169.8			208.7		2.9% - 5.6%
	Rockland term loan, due 2027		85.3			86.5		6.40%
	Other long-term debt		1			0.3		5.5% - 6.7%
	Less: current maturities		(216.2	)		(121.2	)
	Total long-term debt	$	1,254.80		$	1,459.10
	Current maturities consist of the following:
		December 31,			December 31,			Interest Rate
		2013			2012
	Current Maturities:
	Senior unsecured notes, due July 2014	$	190		$	—		5.90%
	Epsilon Power Partners term facility, due 2019		5			3		7.40%
	Cadillac term loan, due 2025		2			2.4		6.0% - 8.0%
	Piedmont construction loan, due 2014(1)		12.6			55.1		Libor plus 3.5%
	Meadow Creek term loan, due 2024(2)		4.9			59.5		2.9% - 5.6%
	Rockland term loan, due 2027		1.5			1.2		6.40%
	Other short-term debt		0.2			—		5.5 - 6.7%
	Total current maturities	$	216.2		$	121.2
	-1
	The terms of the Piedmont project-level debt financing included a $51.0 million bridge loan and an $82.0 million construction loan ($76.6 million at December 31, 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. On February 14, 2014, we paid down $8.1 million of principal on the construction loan and converted the remaining $68.5 million to a term loan due August 2018 with an interest rate of LIBOR plus an applicable margin ranging from 3.5% to 4.0%.
	-2
	The terms of the Meadow Creek project-level debt financing included a $56.5 million cash grant loan and a $169.8 million term 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 us to cover the shortfall from lower grant-eligible costs than anticipated, primarily as a result of a lower project cost as compared to budget.
	-3
	The Curtis Palmer Notes, Series A senior guaranteed notes due August 2015 and Series B senior guaranteed notes due August 2017 were retired on February 26, 2014 with a portion of the proceeds from the New Senior Secured Credit Facilities described below.
	Principal payments on the maturities of our debt due in the next five years and thereafter are as follows:
	2014	$	216.2
	2015		170.6
	2016		19
	2017		96.5
	2018		529.5
	Thereafter		439.2
		$	1,471.00
	Notes of Atlantic Power Corporation
	On November 5, 2011, we completed a private placement of $460.0 million aggregate principal amount of 9.0% senior notes due 2018 (the "Senior Notes") to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"), and to non-U.S. persons outside of the United States in compliance with Regulation S under the Securities Act. The Senior Notes were issued at an issue price of 97.471% of the face amount of the Atlantic Notes for aggregate gross proceeds to us of $448.0 million. The Atlantic Notes are senior unsecured obligations, guaranteed by certain of our subsidiaries.
	Notes of the Partnership
	The Partnership, a wholly-owned subsidiary acquired on November 5, 2011, has outstanding Cdn$210.0 million ($197.4 million as of December 31, 2013) aggregate principal amount of 5.95% senior unsecured notes, due June 2036 (the "Partnership Notes"). Interest on the Partnership Notes is payable semi-annually at 5.95%. Pursuant to the terms of the Partnership Notes, we must meet certain financial and other covenants, including a financial covenant generally based on the ratio of debt to capitalization of the Partnership. The Partnership Notes are guaranteed by Atlantic Power Preferred Equity Ltd., an indirect, wholly-owned subsidiary acquired in connection with the acquisition of the Partnership.
	Notes of Curtis Palmer LLC
	See New Senior Secured Credit Facilities below for discussion of the retirement of the 5.90% senior unsecured notes, due July 2014 (the "Curtis Palmer Notes") in February 2014.
	The Curtis Palmer Notes had $190.0 million aggregate principal outstanding at December 31, 2013. Interest on the Curtis Palmer Notes is payable semi-annually at 5.90%. Pursuant to the terms of the Curtis Palmer Notes, we must meet certain financial and other covenants, including a financial covenant generally based on the ratio of debt to capitalization of the Partnership. The Curtis Palmer Notes are guaranteed by the Partnership.
	Notes of Atlantic Power (US) GP
	See New Senior Secured Credit Facilities below for discussion of the retirement of these Notes of Atlantic Power (US) GP in February 2014.
	Atlantic Power (US) GP, an indirect, wholly-owned subsidiary acquired in connection with the acquisition of the Partnership, has outstanding $150.0 million aggregate principal amount of 5.87% senior guaranteed notes, Series A, due August 2015 (the "Series A Notes"). Interest on the Series A Notes is payable semi-annually at 5.87%. Atlantic Power (US) GP has also outstanding $75.0 million aggregate principal amount of 5.97% senior guaranteed notes, Series B, due August 2017 (the "Series B Notes" and together with the Series A Notes, the "Notes"). Interest on the Series B Notes is payable semi-annually at 5.97%. Pursuant to the terms of the Series A Notes and the Series B Notes, we must meet certain financial and other covenants, including a financial covenant generally based on the ratio of debt to capitalization of the Partnership and Atlantic Power (US) GP. The Series A Notes and the Series B Notes are guaranteed by Atlantic Power, the Partnership, Curtis Palmer LLC and the existing and future guarantors of Atlantic Power's Senior Notes, senior credit facility and refinancings thereof.
	On June 22, 2012, Atlantic Power, Atlantic Power (US) GP and certain other of our subsidiaries entered into an amendment to the Note Purchase and Parent Guaranty Agreement, dated as of August 15, 2007 (the "Note Purchase Agreement"), which governs the Series A Notes and the Series B Notes of Atlantic Power (US) GP. Under the amendment, we agreed: (i) that Atlantic Power and the existing and future guarantors of Senior Notes, our senior credit facility and refinancings thereof would provide guarantees of the Notes; (ii) to shorten the maturity of the Series A Notes from August 15, 2017 to August 15, 2015; (iii) to shorten the maturity of the Series B Notes from August 15, 2019 to August 15, 2017; (iv) to include an event of default that would be triggered if certain defaults occurred under the debt instruments of Atlantic Power and certain of its subsidiaries; and (v) to add certain covenants, including covenants that limit the ability of Curtis Palmer LLC ("Curtis Palmer"), a wholly-owned subsidiary of the Partnership to incur debt or liens, make distributions other than in the ordinary course of business, prepay debt or sell material assets and that limit our ability to sell Curtis Palmer. The parties entered into the amendment following a series of discussions concerning our acquisition of the Partnership. Although we believe that the acquisition of the Partnership was in full compliance with the terms and conditions of the Note Purchase Agreement, the holders of the Notes agreed to waive certain defaults or events of default that they alleged may have occurred as a result of our acquisition of the Partnership in return for Atlantic Power and its subsidiaries entering into the amendment.
	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. At December 31, 2013, all of our projects were in compliance with the covenants contained in project-level debt.
	Senior Credit Facility
	See the discussion of the New Senior Secured Credit Facilities below for the replacement of this facility in February 2014.
	On November 5, 2011, we entered into an amended and restated credit agreement, pursuant to which we increased the capacity under our then existing credit facility from $100 million to $300 million on a senior secured basis, $200 million of which could be utilized for letters of credit (the "old credit facility"). Borrowings under the old credit facility were available in U.S. dollars and Canadian dollars and bore interest at a variable rate equal to the U.S. Prime Rate, the London Interbank Offered Rate or the Canadian Prime Rate, as applicable, plus an applicable margin of between 0.75% and 3.00% that varies based on our corporate credit rating. The old credit facility had a maturity date of November 4, 2015.
	On November 2, 2012, we amended the old credit facility in order to change certain financial and leverage ratio covenants. These changes involved the better accommodation of construction stage projects with no historical financial performance, the better accommodation of the possibility of certain asset sales, including our Florida Projects, by waiving a material disposition covenant and permitting inclusion of the disposed assets' trailing twelve months EBITDA for covenant calculations, and the better accommodation of the same possible asset sales by temporarily modifying the Total Leverage Ratio.
	The old credit facility, as amended on November 12, 2012, contained customary representations, warranties, terms and conditions, as well as covenants limiting our ability to, among other things, incur additional indebtedness, merge or consolidate with others, change our business, and sell or dispose of assets. The covenants also included 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 amended credit facility. We were required to meet certain financial covenants under the terms of the amended credit facility, which were generally based on ratios of debt to EBITDA and EBITDA to interest. At a ratio of 7.25 of debt to EBITDA, we were restricted from paying dividends to our shareholders. The old credit facility, as amended on November 12, 2012, was secured by pledges of certain assets and interests in certain subsidiaries.
On August 2, 2013 we entered into an amendment to the old credit facility with our lenders (the old credit facility, as amended by the August 2, 2013 amendment, the "prior credit facility"). The most significant changes to the prior credit facility include the following:
•
a decrease in capacity from $300 million to $150 million, all of which could have been 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 could have been 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 prior credit facility exceeded $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 have been pledged to the lenders as security for the prior credit facility;
•
an amendment to the maximum permissible Consolidated Total Net Debt to Consolidated EBITDA (each as defined in the prior 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 prior 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 prior credit facility, which fee varies based on our unsecured debt rating (currently, the applicable commitment fee is 1.50%); and
•
an amendment to the maturity date from November 4, 2015 to March 4, 2015.
Among other restrictions set forth in the prior credit facility, we were restricted from paying cash dividends to our shareholders if we did not comply with the financial covenants specified above. The prior credit facility was secured by pledges of certain assets and interests in certain subsidiaries. The old credit facility contained customary representations, warranties, terms and conditions, and covenants, certain of which were amended in the prior credit facility. The amended covenants limited 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 amended covenants also included 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 prior credit facility. Specifically, under the prior credit facility, we were 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 credit facility, we had the right generally to repurchase substantially more of our outstanding debt issuances, subject to the satisfaction of certain conditions. Under the prior credit facility, 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 prior credit facility were available in U.S. dollars and Canadian dollars and bore 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 August credit facility), as applicable, plus a margin of between 2.75% and 4.75% that varies based on our unsecured debt rating. At December 31, 2013, the prior credit facility was undrawn and the applicable LIBOR margin was 4.25%. At December 31, 2013, $97.2 million was issued in letters of credit, but not drawn, to support contractual credit requirements at several of our projects.
New Senior Secured Credit Facilities
On February 24, 2014 the Partnership, our wholly-owned indirect subsidiary, entered into the New Senior Secured Credit Facilities, including the New Term Loan Facility, comprising of $600 million in aggregate principal amount, and the New Revolving Credit Facility with a capacity of $210 million. Borrowings under the New Senior Secured Credit Facilities are available in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted Eurodollar Rate, the Base Rate or the Canadian Prime Rate, each as defined in the credit agreement governing the New Senior Secured Credit Facilities (the "Credit Agreement"), as applicable, plus an applicable margin between 2.75% and 3.75% that varies depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The applicable margin for term loans bearing interest at the Adjusted Eurodollar Rate and the Base Rate is 3.75% and 2.75% respectively. The Adjusted Eurodollar Rate cannot be less than 1.00%.
The New Term Loan Facility matures on February 24, 2021. The revolving commitments under the New Revolving Credit Facility terminates on February 24, 2018. Letters of credit are available to be issued under the revolving commitments until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. The Partnership is required to pay a commitment fee with respect to the commitments under the New Revolving Credit Facility equal to 0.75% times the average of the daily difference between the revolving commitments and all outstanding revolving loans (excluding swing line loans) plus amounts available to be drawn under letters of credit and all outstanding reimbursement obligations with respect to drawn letters of credit.
The New Senior Secured Credit Facilities are secured by a pledge of the equity interests in the Partnership and its subsidiaries, guaranties from the Partnership subsidiary guarantors and a limited recourse guaranty from the entity that holds all of the Partnership equity, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment of all revenues, funds and accounts of the Partnership and its subsidiaries (subject to certain exceptions), and certain other assets. The New Senior Secured Credit Facilities are not otherwise guaranteed or secured by us or any of our subsidiaries (other than the Partnership subsidiary guarantors). The New Senior Secured Credit Facilities will also have the benefit of a debt service reserve account, which is required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service.
The Partnership's existing Cdn$210 million Notes of the Partnership prohibit the Partnership (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the Notes of the Partnership are secured equally and ratably with such other indebtedness. Accordingly, in connection with the execution of the Credit Agreement, the Partnership has granted an equal and ratable security interest in the collateral package securing the New Senior Secured Credit Facilities under the indenture governing the Notes of the Partnership for the benefit of the holders of the Notes of the Partnership.
The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The covenants include a requirement that the Partnership and its subsidiaries maintain a Leverage Ratio (as defined in the Credit Agreement) ranging from 5.50:1.00 in 2014 to 4.00:1.00 in 2021, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 2.50:1.00 in 2014 to 3.25:1.00 in 2021. In addition, the Credit Agreement includes customary restrictions and limitations on the Partnership's and its subsidiaries' ability to (i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to customary carve-outs and exceptions and various thresholds.
Under the Credit Agreement, if a change of control (as defined in the Credit Agreement) occurs, unless the Partnership elects to make a voluntary prepayment of the term loans under the New Senior Secured Credit Facilities, it will be required to offer each electing lender to prepay such lender's term loans under the New Senior Secured Credit Facilities at a price equal to 101% of par. In addition, in the event that the Partnership elects to repay, prepay or refinance all or any portion of the term loan facilities within one year from the initial funding date under the Credit Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid or refinanced.
The Credit Agreement also contains a mandatory amortization feature and customary mandatory prepayment provisions, including: (i) from proceeds of assets sales, insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and (ii) the payment of 50% of the excess cash flow, as defined in the Credit Agreement, of the Partnership and its subsidiaries.
Under certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or warranties in any material respect, non-payment or acceleration of other material debt of the Partnership and its subsidiaries, bankruptcy, material judgments rendered against the Partnership or certain of its subsidiaries, certain ERISA or regulatory events, a change of control of the Partnership, or defaults under certain guaranties and collateral documents securing the New Senior Secured Credit Facilities, in each case subject to various exceptions and notice, cure and grace periods.
On February 26, 2014, $600 million was drawn under the New Term Loan Facility, and letters of credit in an aggregate face amount of $144 million were issued (but not drawn) pursuant to the revolving commitments under the New Revolving Credit Facility and used (i) to fund a debt service reserve in an amount equivalent to six months of debt service (approximately $15.8 million), and (ii) to support contractual credit support obligations of the Partnership and its subsidiaries and of certain other of our affiliates.
We and our subsidiaries have used the proceeds from the New Term Loan Facility under the New Senior Secured Credit Facilities to:
•
optionally prepay or redeem in whole, at a price equal to par plus accrued interest and applicable make-whole premium, of (i) the $150 million aggregate principal amount outstanding of 5.87% Senior Guaranteed Notes, Series A, due 2015 and the $75 million aggregate principal amount outstanding of 5.97% Senior Guaranteed Notes, Series B, due 2017 issued by Atlantic Power (US) GP, and (ii) the $190 million aggregate principal amount outstanding of 5.9% Senior Notes due 2014 issued by Curtis Palmer LLC;
•
pay transaction costs and expenses; and
•
make a distribution to us in the range of approximately $120 million to $125 million, which we may use for any corporate purpose, including, at our discretion, additional debt reduction which may, taking into account available funds, market conditions and other relevant factors, include steps to repurchase or redeem, by means of a tender offer or otherwise, up to $150 million aggregate principal amount of the Notes of Atlantic Power Corporation and up to Cdn$46 million of our 6.50% convertible debentures due October 31, 2014.
In connection with the funding of the New Senior Secured Credit Facilities described above, we terminated the prior credit facility on February 26, 2014.
In addition, the Prior Credit Facility contained certain guaranties, which were terminated in connection with the termination of the Prior Credit Facility. In addition, the terms of the Notes of Atlantic Power Corporation provide that the guarantors of the Prior Credit Facility guarantee the Notes of Atlantic Power Corporation. As a result, upon termination of the Prior Credit Facility and the related guaranties, the guaranties under the Notes of Atlantic Power Corporation were cancelled and the guarantors of the Notes of Atlantic Power Corporation were automatically released from all of their obligations under such guaranties.
The foregoing description of the New Senior Secured Credit Facilities is qualified in its entirety by reference to the full text of the credit agreement governing the Senior Secured Credit Facilities, which is attached to this Annual Report on Form 10-K as Exhibit 10.1 and is incorporated herein by reference.

Convertible_debentures

Convertible debentures	12 Months Ended
	Dec. 31, 2013
Convertible debentures	'
Convertible debentures	'
	11. Convertible debentures
	The following table provides details related to outstanding convertible debentures:
		6.50%			6.25%			5.60%			5.75%		6.00%			Total
		Debentures			Debentures			Debentures			Debentures		Debentures
		due			due			due			due		due
		Oct-14			Mar-17			Jun-17			Jun-19		Dec-19
	Balance at December 31, 2011	$	44.1		$	66.3		$	79.2		$	—	$	—		$	189.6
	Issuance of convertible debentures		—			—			—			130		100.6			230.6
	Foreign exchange (gain) loss		1			1.5			1.8			—		(0.3	)		4
	Balance at December 31, 2012	$	45.1		$	67.8		$	81		$	130	$	100.3		$	424.2
	Foreign exchange (gain) loss		(3.0	)		(4.4	)		(5.3	)		—		(6.3	)		(19.0	)
	Balance at December 31, 2013	$	42.1		$	63.4		$	75.7		$	130	$	94		$	405.2
	Aggregate interest expense related to the convertible debentures was $24.2 million, $12.1 million, and $12.1 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	In 2006 we issued, in a public offering, Cdn$60 million aggregate principal amount of 6.25% convertible secured debentures (the "2006 Debentures") for gross proceeds of $52.8 million. The 2006 Debentures pay interest semi-annually on April 30 and October 31 of each year. The 2006 Debentures had an initial maturity date of October 31, 2011 and are convertible into approximately 80.6452 common shares per Cdn$1,000 principal amount of 2006 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share. The 2006 Debentures are secured by a subordinated pledge of our interest in certain subsidiaries and contain certain restrictive covenants. In connection with our conversion to a common share structure on November 27, 2009, the holders of the 2006 Debentures approved an amendment to increase the annual interest rate from 6.25% to 6.50% and separately, an extension of the maturity date from October 2011 to October 2014. As of December 31, 2013, Cdn$15.2 million of the 2006 Debentures, have been converted to 1.2 million common shares. The 2006 Debentures are classified as a current liability for the year ended December 31, 2013.
	On December 17, 2009, we issued, in a public offering, Cdn$86.3 million aggregate principal amount of 6.25% convertible unsecured debentures (the "2009 Debentures") for gross proceeds of $82.1 million. The 2009 Debentures pay interest semi-annually on March 15 and September 15 of each year. The 2009 Debentures mature on March 15, 2017 and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share. As of December 31, 2013, Cdn$18.8 million of the 2009 Debentures, have been converted to 1.4 million common shares.
	On October 20, 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60% convertible unsecured subordinated debentures (the "2010 Debentures") for gross proceeds of $78.9 million. The 2010 Debentures pay interest semi-annually on June 30 and December 30 of each year. The 2010 Debentures mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of 2010 Debentures, at any time, at the option of the holder, representing an initial conversion price of approximately Cdn$18.10 per common share.
	On July 5, 2012, we issued, in a public offering, $130.0 million aggregate principal amount of 5.75% convertible unsecured subordinated debentures due June 30, 2019, (the "July 2012 Debentures") for net proceeds of $124.0 million. The July 2012 Debentures pay interest semi-annually on the last day of June and December of each year. The July 2012 Debentures are convertible into our common shares at an initial conversion rate of 57.9710 common shares per $1,000 principal amount of July 2012 debentures representing a conversion price of $17.25 per common share. We used the proceeds to fund a portion of our equity commitment in Canadian Hills.
	On December 11, 2012, we issued, in a public offering, Cdn$100 million aggregate principal amount of 6.00% convertible unsecured subordinated debentures due December 31, 2019 (the "December 2012 Debentures") for net proceeds of Cdn$95.5 million. The December 2012 Debentures pay interest semi-annually on the last day of June and December of each year beginning June 30, 2013. The December 2012 Debentures are convertible into our common shares at an initial conversion rate of 68.9655 common shares per Cdn$1,000 principal amount of December 2012 Debentures representing a conversion price of Cdn$14.50 per common share. We used the proceeds to acquire all of the outstanding shares of capital stock of Ridgeline and to fund certain working capital commitments and acquisition expenses related to Ridgeline.

Fair_value_of_financial_instru

Fair value of financial instruments	12 Months Ended
	Dec. 31, 2013
Fair value of financial instruments	'
Fair value of financial instruments	'
	12. Fair value of financial instruments
	The estimated carrying values and fair values of our recorded financial instruments related to operations are as follows:
		December 31,
		2013				2012
		Carrying		Fair		Carrying		Fair
		Amount		Value		Amount		Value
	Cash and cash equivalents	$	158.6	$	158.6	$	60.2	$	60.2
	Restricted cash		114.2		114.2		28.6		28.6
	Derivative assets current		0.2		0.2		9.5		9.5
	Derivative assets non-current		13		13		11.1		11.1
	Derivative liabilities current		28.5		28.5		33		33
	Derivative liabilities non-current		76.1		76.1		118.1		118.1
	Revolving credit facility and long-term debt, including current portion		1,471.00		1,435.20		1,647.30		1,701.80
	Convertible debentures		405.2		281.1		424.2		416.7
	Our financial instruments that are recorded at fair value have been classified into levels using a fair value hierarchy.
	The three levels of the fair value hierarchy are defined below:
	Level 1—Unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Financial assets utilizing Level 1 inputs include active exchange-traded securities.
	Level 2—Quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data.
	Level 3—Unobservable inputs from objective sources. These inputs may be based on entity-specific inputs. Level 3 inputs include all inputs that do not meet the requirements of Level 1 or Level 2.
	The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of December 31, 2013 and December 31, 2012. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
		December 31, 2013
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	158.6	$	—	$	—	$	158.6
	Restricted cash		114.2		—		—		114.2
	Derivative instruments asset		—		13.2		—		13.2
	Total	$	272.8	$	13.2	$	—	$	286
	Liabilities:
	Derivative instruments liability	$	—	$	104.6	$	—	$	104.6
	Total	$	—	$	104.6	$	—	$	104.6
		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 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 December 31, 2013, the credit valuation adjustments resulted in an $11.1 million net increase in fair value, which consists of a $0.5 million pre-tax gain in other comprehensive income and a $10.6 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 $1.1 million pre-tax gain in other comprehensive income and a $13.8 million gain in change in fair value of derivative instruments and $3.6 million related to interest rate swaps assumed in the acquisition of Ridgeline.
	The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature. The fair value of long-term debt and convertible debentures was determined using quoted market prices, as well as discounting the remaining contractual cash flows using a rate at which we could issue debt with a similar maturity as of the balance sheet date.

Accounting_for_derivative_inst

Accounting for derivative instruments and hedging activities	12 Months Ended
	Dec. 31, 2013
Accounting for derivative instruments and hedging activities	'
Accounting for derivative instruments and hedging activities	'
	13. Accounting for derivative instruments and hedging activities
	We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. We have one contract designated as a cash flow hedge, 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 our other 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 December 31, 2013. 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 December 31, 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 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 swaps to effectively fix the price of 3.2 million Mmbtu of future natural gas purchases, or approximately 64% 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 25% of our share of the expected natural gas purchases at the project during 2016 and 2017.
	In February 2014, we paid $4.0 million to terminate these contracts as a result of terminating the Prior Credit Facility. We and will record fuel expense related to the settlement in the first quarter of 2014.
	Interest rate swaps
	The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.02% through February 15, 2015, 6.14% from February 16, 2015 to February 15, 2019, 6.26% from February 16, 2019 to February 15, 2023, and 6.38% 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).
	The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.75% through February 29, 2016. From February 2016 until the maturity of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.47%. The swap continues at the fixed rate of 4.47% 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 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.
	As a result of the Piedmont term loan conversion on February 14, 2013, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. We will record $0.6 million of interest expense related to this transaction in the first quarter of 2014.
	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 7.37% 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 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.
	In February 2014, we paid $2.6 million to terminate this contract as a result of terminating the Prior Credit Facility. We will record interest expense related to its settlement in the first quarter of 2014.
	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 through 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.
	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% through 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 any future payments of dividends to shareholders. 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 74% 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 December 31, 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 February 2014, we paid $0.4 million to terminate these contracts as a result of terminating the Prior Credit Facility. We will record a foreign exchange related to their settlement in the first quarter of 2014.
	Volume of forecasted transactions
	We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption as of year ended December 31, 2013 and December 31, 2012:
		Units		December 31,			December 31,
				2013			2012
	Natural gas swaps	Natural Gas (Mmbtu)			5.6			10.6
	Gas purchase agreements	Natural Gas (Gigajoules)			41.1			49.8
	Interest rate swaps	Interest (US$)			161.2			172
	Currency forwards	Cdn$			34.9			176.6
	Fair value of derivative instruments
	We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:
		December 31, 2013
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			2.6
	Total derivative instruments designated as cash flow hedges		—			3.9
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.3
	Interest rate swaps long-term		11.5			8.1
	Foreign currency forward contracts current		0.5			0.7
	Foreign currency forward contracts long-term		1.2			—
	Natural gas swaps current		0.3			1.3
	Natural gas swaps long-term		—			3.5
	Gas purchase agreements current		0.2			18.4
	Gas purchase agreements long-term		—			61.9
	Total derivative instruments not designated as cash flow hedges		13.7			101.2
	Total derivative instruments	$	13.7		$	105.1
		December 31, 2012
		Derivative			Derivative
		Assets			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			—
	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:
For the year ended December 31, 2013	Interest			Natural			Total
	Rate			Gas
	Swaps			Swaps
Accumulated OCI balance at January 1, 2013	$	(1.5	)	$	0.1		$	(1.4	)
Change in fair value of cash flow hedges		0.7			—			0.7
Realized from OCI during the period		1			(0.1	)		0.9
Accumulated OCI balance at December 31, 2013	$	0.2		$	—		$	0.2
Gains expected to be realized from OCI in the next 12 months, net of $0.6 tax	$	1		$	—		$	1
For the year ended December 31, 2012	Interest			Natural			Total
	Rate			Gas
	Swaps			Swaps
Accumulated OCI balance at January 1, 2012	$	(1.7	)	$	0.3		$	(1.4	)
Change in fair value of cash flow hedges		(0.9	)		—			(0.9	)
Realized from OCI during the period		1.1			(0.2	)		0.9
Accumulated OCI balance at December 31, 2012	$	(1.5	)	$	0.1		$	(1.4	)
For the year ended December 31, 2011	Interest			Natural			Total
	Rate			Gas
	Swaps			Swaps
Accumulated OCI balance at January 1, 2011	$	(0.4	)	$	0.6		$	0.2
Change in fair value of cash flow hedges		(2.6	)		—			(2.6	)
Realized from OCI during the period		1.4			(0.4	)		1
Accumulated OCI balance at December 31, 2011	$	(1.6	)	$	0.2		$	(1.4	)
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:
			Year ended December 31,
	Classification of (gain)
	loss recognized in income		2013			2012			2011
Gas purchase agreements	Fuel		$	56.5		$	43.5		$	—
Interest rate swaps	Interest, net			9.9			4.6			4.2
Foreign currency forwards	Foreign exchange (gain) loss			(14.4	)		(18.5	)		5.2
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:
			Year ended December 31,
	Classification of (gain) loss
	recognized in income		2013			2012			2011
Natural gas swaps	Change in fair value of derivatives		$	(0.7	)	$	(1.2	)	$	(2.4	)
Gas purchase agreements	Change in fair value of derivatives			19.2			(57.0	)		—
Interest rate swaps	Change in fair value of derivatives			31			(1.1	)		(12.2	)
			$	49.5		$	(59.3	)	$	(14.6	)
Foreign currency forwards	Foreign exchange loss		$	19.4		$	12		$	14.2

Income_taxes

Income taxes	12 Months Ended
	Dec. 31, 2013
Income taxes	'
Income taxes	'
	14. Income taxes
		Year ended December 31
		2013			2012			2011
	Current income tax expense (benefit)	$	7.8		$	6		$	(1.2	)
	Deferred tax benefit		(27.3	)		(34.1	)		(9.9	)
	Total income tax benefit, net	$	(19.5	)	$	(28.1	)	$	(11.1	)
	The following is a reconciliation of income taxes calculated at the Canadian enacted statutory rate of 26.0%, 25.0%, and 26.5% at December 31, 2013, 2012 and 2011, respectively, to the provision for income taxes in the consolidated statements of operations:
		Year ended December 31,
		2013			2012			2011
	Computed income taxes at Canadian statutory rate	$	(9.7	)	$	(36.2	)	$	(22.0	)
	Decreases resulting from:
	Operating countries with different income tax rates		(2.9	)		(8.5	)		(10.6	)
		$	(12.6	)	$	(44.7	)	$	(32.6	)
	Change in valuation allowance		12.1			20.2			21.7
			(0.5	)		(24.5	)		(10.9	)
	Dividend withholding tax and other cash taxes		3.7			5.9			0.4
	Foreign exchange		(9.9	)		1.5			(0.1	)
	Permanent differences		—			(6.5	)		(1.5	)
	Non-deductible acquisition costs		—			0.6			4.3
	Non-deductible interest expense		—			—			2.1
	Changes in tax rates		(4.1	)		1.8			—
	Federal grant		(18.9	)		—			(6.6	)
	Production tax credits		(4.5	)		—			—
	Changes in estimates of tax basis of equity method investments		(1.4	)		(5.1	)		2.2
	Goodwill impairment		13.6			—			—
	Other		2.5			(1.8	)		(1.0	)
			(19.0	)		(3.6	)		(0.2	)
		$	(19.5	)	$	(28.1	)	$	(11.1	)
	The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are presented below:
		2013			2012
	Deferred tax assets:
	Loss carryforwards	$	254.1		$	130.2
	Other accrued liabilities		0.4			10.9
	Finance and share issuance costs		6.7			8.3
	Disallowed interest carryforward		1.7			2.2
	Derivative contracts		27.8			3.5
	Other		8			6.1
	Total deferred tax assets		298.7			161.2
	Valuation allowance		(128.1	)		(116.0	)
			170.6			45.2
	Deferred tax liabilities:
	Intangible assets		(74.2	)		(113.3	)
	Property, plant and equipment		(194.8	)		(94.7	)
	Other long-term investments		(13.1	)		(1.2	)
	Total deferred tax liabilities		(282.1	)		(209.2	)
	Net deferred tax liability	$	(111.5	)	$	(164.0	)
	The following table summarizes the net deferred tax position as of December 31, 2013 and 2012:
		2013			2012
	Long-term deferred tax liabilities	$	(111.5	)	$	(164.0	)
	Net deferred tax liability	$	(111.5	)	$	(164.0	)
	As of December 31, 2013, we have recorded a valuation allowance of $128.1 million. This amount is comprised primarily of provisions against available 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 the entire deferred tax asset will be realized. The ultimate realization of the deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.
	Tax benefits related to uncertain tax positions taken or expected to be taken on a tax return are recorded when such benefits meet a more likely than not threshold. Otherwise, these tax benefits are recorded when a tax position has been effectively settled, which means that the statute of limitation has expired or the appropriate taxing authority has completed their examination even though the statute of limitations remains open. Interest and penalties related to uncertain tax positions are recognized as part of the provision for income taxes and are accrued beginning in the period that such interest and penalties would be applicable under relevant tax law until such time that the related tax benefits are recognized. As of December 31, 2013, we have not recorded any tax benefits related to uncertain tax positions.
	As of December 31, 2013, we had the following net operating loss carryforwards that are scheduled to expire in the following years:
	2027	$	50.3
	2028		101.6
	2029		82.5
	2030		25.8
	2031		57.3
	2032		85.6
	2033		299.3
		$	702.4

Equity_compensation_plans

Equity compensation plans	12 Months Ended
	Dec. 31, 2013
Equity compensation plans	'
Equity compensation plans	'
	15. Equity compensation plans
	Long-term incentive plan
	The following table summarizes the changes in outstanding LTIP notional units during the years ended December 31, 2013, 2012 and 2011:
		Units			Grant Date
					Weighted-Average
					Fair Value per Unit
	Outstanding at December 31, 2010		600,981		$	10.28
	Granted		216,110			14.02
	Additional shares from dividends		36,204			11.04
	Forfeitures		(103,991	)		11.55
	Vested and redeemed		(263,523	)		9.4
	Outstanding at December 31, 2011		485,781			11.49
	Granted		233,752			14.67
	Additional shares from dividends		38,667			13.43
	Forfeitures		(28,932	)		13.63
	Vested and redeemed		(236,733	)		10.18
	Outstanding at December 31, 2012		492,535			13.9
	Granted		597,031			4.91
	Additional shares from dividends		64,576			8.74
	Forfeitures		(184,458	)		8.17
	Vested and redeemed		(202,696	)		13.48
	Outstanding at December 31, 2013		766,988		$	7.86
	The fair value of all outstanding notional units under the LTIP was $4.8 million and $6.3 million for the years ended December 31, 2013 and 2012. Compensation expense related to LTIP was $2.2 million, $2.5 million and $3.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. Cash payments made for vested notional units were $0.9 million, $1.1 million and $1.5 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	The fair value of awards granted under the amended LTIP with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. The Monte Carlo simulation model utilizes multiple input variables over the performance period in order to determine the likely relative total shareholder return. The Monte Carlo simulation model simulated our total shareholder return and for our peer companies during the remaining time in the performance period with the following inputs: (i) stock price on the measurement date, (ii) expected volatility, (iii) risk-free interest rate, (iv) dividend yield and (v) correlations of historical common stock returns between Atlantic Power Corporation and the peer companies. Expected volatilities utilized in the Monte Carlo model are based on our historical volatility and of our peer companies' stock prices over a period equal in length to that of the remaining vesting period. The risk free interest rate is derived from the U.S. Treasury yield curve in effect at the time of grant with a term equal to the performance period assumption at the time of grant. Both the total shareholder return performance and the fair value of the notional units under the Monte Carlo simulation are determined with the assistance of a third party.
	The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period included the following assumptions:
		December 31, 2013			December 31, 2012
	Weighted average risk free rate of return		0.1 - 0.5	%		0.1 - 0.3	%
	Dividend yield		10.8	%		10.1	%
	Expected volatility—Atlantic Power		50.4	%		22.5	%
	Expected volatility—peer companies		11.4 - 56.4	%		11.9 - 97.1	%
	Weighted average remaining measurement period		1.82 years			1.39 years

Defined_benefit_plan

Defined benefit plan	12 Months Ended
	Dec. 31, 2013
Defined benefit plan	'
Defined benefit plan	'
	16. Defined benefit plan
	We sponsor and operate a defined benefit pension plan that is available to certain legacy employees of the Partnership. The Atlantic Power Services Canada LP Pension Plan (the "Plan") is maintained solely for certain eligible legacy Partnership participants. The Plan is a defined benefit pension plan that allows for employee contributions. We expect to contribute $1.4 million to the pension plan in 2014.
	The net annual periodic pension cost related to the pension plan for the years ended December 31, 2013 and 2012 includes the following components:
		2013			2012
	Service cost benefits earned	$	0.9		$	0.8
	Interest cost on benefit obligation		0.7			0.6
	Expected return on plan assets		(0.8	)		(0.6	)
	Gain amortization		0.1			—
	Net period benefit cost	$	0.9		$	0.8
	A comparison of the pension benefit obligation and related plan assets for the pension plan is as follows:
		2013			2012
	Benefit obligation at January 1	$	(16.8	)	$	(12.7	)
	Service cost		(0.9	)		(0.8	)
	Interest cost		(0.7	)		(0.6	)
	Actuarial (gain) loss		1.4			(2.3	)
	Employee contributions		(0.1	)		(0.1	)
	Benefits paid		0.1			—
	Foreign currency translation adjustment		1			(0.3	)
	Benefit obligation at December 31		(16.0	)		(16.8	)
	Fair value of plan assets at January 1	$	12			10.5
	Actual return on plan assets		1.8			0.8
	Employer contributions		2.3			0.4
	Employee contributions		0.1			0.1
	Benefits paid		(0.1	)		—
	Foreign currency translation adjustment		(1.0	)		0.2
	Fair value of plan assets at December 31		15.1			12
	Funded status at December 31—excess of obligation over assets	$	(0.9	)	$	(4.8	)
	Amounts recognized in the balance sheet were as follows:
		2013			2012
	Non-current liabilities	$	0.9		$	4.8
	Amounts recognized in accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows, net of tax:
		2013			2012
	Unrecognized loss	$	0.3		$	1.3
	We estimate that there will be no amortization of net loss for the pension plan from accumulated OCI to net periodic cost over the next fiscal year.
	The following table presents the balances of significant components of the pension plan:
		2013			2012
	Projected benefit obligation	$	16		$	16.8
	Accumulated benefit obligation		12.4			13.1
	Fair value of plan assets		15.1			12
	The market-related value of the pension plan's assets is the fair value of the assets. Plan assets are invested in a common collective trust which totaled $15.1 million and $11.9 million for the years ended December 31, 2013 and 2012 respectively.
	We determine the level in the fair value hierarchy within which the fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the common/collective trust is valued at a fair value which is equal to the sum of the market value of the fund's investments, and is categorized as Level 2. There are no investments categorized as Level 1 or 3.
	The following table presents the significant assumptions used to calculate our benefit obligations:
		2013			2012
	Weighted-Average Assumptions
	Discount rate		5	%		4	%
	Rate of compensation increase		4	%		4	%
	The following table presents the significant assumptions used to calculate our benefit expense:
		2013			2012
	Weighted-Average Assumptions
	Discount rate		4.00%			4.00%
	Rate of return on plan assets		6.00%			5.50%
	Rate of compensation increase		3.0% - 4.0%			3.0% - 4.0%
	We use December 31 as the measurement date for the Plan, and we set the discount rate assumptions on an annual basis on the measurement date. This rate is determined by management based on information provided by our actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of the year ended December 31, 2013 and 2012, was based on the CIA / Natcan curve, which was designed by the Canadian Institute of Actuaries and Natcan Investment Management to provide a means for sponsors of Canadian plans to value the liabilities of their postretirement benefit plans. The CIA / Natcan curve is a hypothetical yield curve represented by extrapolating the corporate AA-rated yield curve beyond 10 years using yields on provincial AA bonds with a spread added to the provincial AA yields to approximate the difference between corporate AA and provincial AA credit risk. The CIA / Natcan curve utilizes this approach because there are very few corporate bonds rated AA or above with maturities of 10 years or more in Canada.
	We employ a balanced total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, and the plan's funded status. Plan assets in the common collective trust are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across Canadian, U.S. and other international equities, as well as among growth, value and small and large capitalization stocks.
	The pension plan assets weighted average allocations in the common collective trust were as follows:
		2013			2012
	Canadian equity		30	%		30	%
	U.S. equity		17	%		13	%
	International equity		15	%		14	%
	Canadian fixed income		38	%		40	%
	International fixed income		—			3	%
			100	%		100	%
	Our expected future benefit payments for each of the next five years and in the aggregate for the five years thereafter, are as follows in Cdn$:
	2013
2014	$	0.1
2015		0.2
2016		0.3
2017		0.3
2018		0.4
2019-2023		3.4

Common_shares

Common shares	12 Months Ended
	Dec. 31, 2013
Common shares	'
Common shares	'
	17. Common shares
	On July 5, 2012, we closed a public offering of 5,567,177 common shares, at a purchase price of $12.76 per common share and Cdn$13.10 per common share, for an aggregate net proceeds from the common share offering, after deducting the underwriting discounts and expenses, of approximately $68.5 million. We used the proceeds to fund our equity commitment in Canadian Hills.
	On November 5, 2011, we issued 31,500,215 common shares as part of the consideration paid in the acquisition of the Partnership. See Note 3(c) for further details.
	On October 19, 2011, we closed a public offering of 12,650,000 of our common shares, which included 1,650,000 common shares issued pursuant to the exercise in full of the underwriters' over-allotment option, at a purchase price of $13.00 per common share sold in U.S. dollars and Cdn$13.26 per common share sold in Canadian dollars, for net proceeds of $155.4 million. We used the net proceeds from the offering to fund a portion of the cash portion of our acquisition of the Partnership.
	Shelf Registrations
	On August 8, 2012, we filed with the SEC an automatic shelf registration statement (Registration No. 333-183135) for the potential offering and sale of debt and equity securities, including common shares issued under our dividend reinvestment program. At that time, because we were a well-known seasoned issuer, as defined in Rule 405 under the Securities Act, the registration statement was effective immediately upon filing. As of the date of the filing of this Annual Report on Form 10-K, as a result of the decrease in our market capitalization we can no longer offer and sell securities under that shelf registration. However, immediately following the filing of this Annual Report on Form 10-K, we intend to file a new registration statement, which will be effectively immediately upon filing, for the continued and uninterrupted issuance of common shares under our dividend reinvestment program.

Preferred_shares_issued_by_a_s

Preferred shares issued by a subsidiary company	12 Months Ended
	Dec. 31, 2013
Preferred shares issued by a subsidiary company	'
Preferred shares issued by a subsidiary company	'
	18. Preferred shares issued by a subsidiary company
	In 2007, a subsidiary acquired in our acquisition of the Partnership issued 5.0 million 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the "Series 1 Shares") priced at Cdn$25.00 per share. Cumulative dividends are payable on a quarterly basis at the annual rate of Cdn$1.2125 per share. Beginning on June 30, 2012, the Series 1 Shares were redeemable by the subsidiary company at Cdn$26.00 per share, declining by Cdn$0.25 each year to Cdn$25.00 per share on or after June 30, 2016, plus, in each case, an amount equal to all accrued and unpaid dividends thereon.
	In 2009, a subsidiary company acquired in our acquisition of the Partnership issued 4.0 million 7.0% Cumulative Rate Reset Preferred Shares, Series 2 (the "Series 2 Shares") priced at Cdn$25.00 per share. The Series 2 Shares pay fixed cumulative dividends of Cdn$1.75 per share per annum, as and when declared, for the initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. On December 31, 2014 and on December 31 every five years thereafter, the Series 2 Shares are redeemable by the subsidiary company at Cdn$25.00 per share, plus an amount equal to all declared and unpaid dividends thereon to, but excluding the date fixed for redemption. The holders of the Series 2 Shares will have the right to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the" Series 3 Shares") of the subsidiary, subject to certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the board of directors of the subsidiary, at a rate equal to the sum of the then 90-day Government of Canada Treasury bill rate and 4.18%.
	The Series 1 Shares, the Series 2 Shares and the Series 3 Shares are fully and unconditionally guaranteed by us and by the Partnership on a subordinated basis as to: (i) the payment of dividends, as and when declared; (ii) the payment of amounts due on a redemption for cash; and (iii) the payment of amounts due on the liquidation, dissolution or winding up of the subsidiary company. If, and for so long as, the declaration or payment of dividends on the Series 1 Shares, the Series 2 Shares or the Series 3 Shares is in arrears, the Partnership will not make any distributions on its limited partnership units and we will not pay any dividends on our common shares.
	The subsidiary company paid aggregate dividends of $12.6 million on the Series 1 Shares and the Series 2 Shares in 2013 as compared to $13.0 million in 2012.

Basic_and_diluted_earnings_los

Basic and diluted earnings (loss) per share	12 Months Ended
	Dec. 31, 2013
Basic and diluted earnings (loss) per share	'
Basic and diluted earnings (loss) per share	'
	19. Basic and diluted earnings (loss) per share
	Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include 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.
	Because we reported a loss for the years ended December 31, 2013, 2012 and 2011, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.
	The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the years ended December 31, 2013, 2012 and 2011:
		2013			2012			2011
	Numerator:
	Loss from continuing operations attributable to Atlantic Power Corporation	$	(26.8	)	$	(126.7	)	$	(72.7	)
	Income (loss) from discontinued operations, net of tax		(6.2	)		13.9			34.3
	Net loss attributable to Atlantic Power Corporation	$	(33.0	)	$	(112.8	)	$	(38.4	)
	Denominator:
	Weighted average basic shares outstanding		119.9			116.4			77.5
	Dilutive potential shares:
	Convertible debentures		27.7			17.4			14
	LTIP notional units		0.7			0.5			0.4
	Potentially dilutive shares		148.3			134.3			91.9
	Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.23	)	$	(1.09	)	$	(0.94	)
	Diluted earnings (loss) per share from discontinued operations		(0.05	)		0.12			0.44
	Diluted loss per share attributable to Atlantic Power Corporation	$	(0.28	)	$	(0.97	)	$	(0.50	)
	Potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares in the years ended December 31, 2013, 2012 and 2011 because their impact would be anti-dilutive.

Assets_held_for_sale

Assets held for sale	12 Months Ended
	Dec. 31, 2013
Assets held for sale	'
Assets held for sale	'
	20. Assets held for sale
	During the fourth quarter of 2013, we sold our 60% interest in Rollcast. Rollcast's net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the years ended December 31, 2013, 2012 and 2011. 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 years ended December 31, 2013, 2012 and 2011. The following tables summarize the revenue, income (loss) from operations, and income tax expense of Rollcast, Path 15 and the Florida Projects for the years ended December 31, 2013, 2012, and 2011:
		December 31,
		2013			2012		2011
	Revenue	$	71.6		$	216.7	$	191
	Income (loss) from discontinued operations		(5.4	)		15.7		37.1
	Income tax expense		0.8			1.8		2.8
	Income (loss) from discontinued operations, net of tax	$	(6.2	)	$	13.9	$	34.3
	Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for the Florida Projects, Path 15 and Rollcast was $(0.05), $0.12, and $0.44 for the years ended December 31, 2013, 2012, and 2011 respectively.
	The following table sets forth the assets and liabilities held for sale for the year ended December 31, 2012:
		December 31,
		2012
	Current assets:
	Cash and cash equivalents	$	6.5
	Restricted cash		12.6
	Accounts receivable		21.9
	Other current assets		6.3
			47.3
	Non-current assets:
	Property, plant, and equipment		111.9
	Transmission system rights		172.4
	Goodwill		8.9
	Other assets		10.9
	Assets held for sale	$	351.4
	Current liabilities:
	Accounts payable and other accrued liabilities	$	16.5
	Current portion of long-term debt		14.3
	Current portion of derivative instrument asset		20
	Other liabilities		0.5
			51.3
	Long term liabilities
	Long-term debt		137.7
	Liabilities held for sale	$	189

Segment_and_geographic_informa

Segment and geographic information	12 Months Ended
	Dec. 31, 2013
Segment and geographic information	'
Segment and geographic information	'
	21. Segment and geographic information
	We have four reportable segments: East, West, Wind and Un-allocated Corporate. We revised our reportable business segments in the fourth quarter of 2013 as the result of recent significant asset sales and in order to align with changes in management's structure, resource allocation and performance assessment in making decisions regarding our operations. Our financial results for the years ended December 31, 2013, 2012 and 2011 have been presented to reflect these changes in operating segments. 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. Path 15, a component of the West segment, and the Auburndale, Lake and Pasco projects, which are components of the East segment, and Rollcast a component of Un-allocated corporate, 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 table below:
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Year ended December 31, 2013
	Project revenues	$	299.1		$	182.3		$	70.8		$	(0.5	)	$	551.7
	Segment assets		1,395.20			1,001.50			853.9			144.4			3,395.00
	Goodwill		107.8			188.5			—			—			296.3
	Capital expenditures		13.8			1.1			11.1			0.2			26.2
	Project Adjusted EBITDA	$	150.7		$	78.8		$	59.6		$	(18.6	)	$	270.5
	Change in fair value of derivative instruments		(24.4	)		—			(25.9	)		—			(50.3	)
	Depreciation and amortization		93.7			68.3			47.3			0.5			209.8
	Interest, net		20.7			0.4			19.5			(2.1	)		38.5
	Other project (income) expense		34.9			(26.3	)		0.1			(0.5	)		8.2
	Project income (loss)		25.8			36.4			18.6			(16.5	)		64.3
	Administration		—			—			—			35.2			35.2
	Interest, net		—			—			—			104.1			104.1
	Foreign exchange gain		—			—			—			(27.4	)		(27.4	)
	Other income, net		—			—			—			(10.5	)		(10.5	)
	Income (loss) from continuing operations before income taxes		25.8			36.4			18.6			(117.9	)		(37.1	)
	Income tax benefit		—			—			—			(19.5	)		(19.5	)
	Net income (loss) from continuing operations		25.8			36.4			18.6			(98.4	)		(17.6	)
	Income (loss) from discontinued operations		(1.1	)		1.3			—			(6.4	)		(6.2	)
	Net income (loss)	$	24.7		$	37.7		$	18.6		$	(104.8	)	$	(23.8	)
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Year ended December 31, 2012
	Project revenues	$	267.5		$	169.6		$	1.9		$	1.4		$	440.4
	Segment assets		1,600.20			1,305.30			956.3			140.9			4,002.70
	Goodwill		138.6			192.6			—			3.5			334.7
	Capital expenditures		25.5			0.2			441.6			0.8			468.1
	Project Adjusted EBITDA	$	145.7		$	82.1		$	10.9		$	(11.1	)	$	227.6
	Change in fair value of derivative instruments		56.6			—			—			—			56.6
	Depreciation and amortization		87.5			71.4			5.9			0.1			164.9
	Interest, net		18.5			0.4			5.1			—			24
	Other project expense		1.2			3			7.3			—			11.5
	Project (loss) income		(18.1	)		7.3			(7.4	)		(11.2	)		(29.4	)
	Administration		—			—			—			28.3			28.3
	Interest, net		—			—			—			89.8			89.8
	Foreign exchange loss		—			—			—			0.5			0.5
	Other income, net		—			—			—			(5.7	)		(5.7	)
	Income (loss) from continuing operations before income taxes		(18.1	)		7.3			(7.4	)		(124.1	)		(142.3	)
	Income tax benefit		—			—			—			(28.1	)		(28.1	)
	Net income (loss) from continuing operations		(18.1	)		7.3			(7.4	)		(96.0	)		(114.2	)
	Income (loss) from discontinued operations		13.6			2.9			—			(2.6	)		13.9
	Net income (loss)	$	(4.5	)	$	10.2		$	(7.4	)	$	(98.6	)	$	(100.3	)
		East			West			Wind			Un-allocated Corporate			Consolidated
	Year ended December 31, 2011
	Project revenues	$	66		$	26.6		$	—		$	1.3		$	93.9
	Segment assets		1,683.90			1,392.10			48.6			123.8			3,248.40
	Goodwill		138.6			201.5			—			3.5			343.6
	Capital expenditures		115			0.1			—			—			115.1
	Project Adjusted EBITDA	$	66.8		$	16.4		$	4.3		$	(0.7	)	$	86.8
	Change in fair value of derivative instruments		17.5			—			—			(0.3	)		17.2
	Depreciation and amortization		37.3			15.2			3			—			55.5
	Interest, net		11.5			0.8			2.9			—			15.2
	Other project (income) expense		2.6			(0.3	)		—			0.2			2.5
	Project (loss) income		(2.1	)		0.7			(1.6	)		(0.6	)		(3.6	)
	Administration		—			—			—			37.7			37.7
	Interest, net		—			—			—			26			26
	Foreign exchange loss		—			—			—			13.8			13.8
	Other income, net		—			—			—			(0.1	)		(0.1	)
	Income (loss) from continuing operations before income taxes		(2.1	)		0.7			(1.6	)		(78.0	)		(81.0	)
Income tax benefit		—			—			—			(11.1	)		(11.1	)
Net income (loss) from continuing operations		(2.1	)		0.7			(1.6	)		(66.9	)		(69.9	)
Income (loss) from discontinued operations		31.8			4.4			—			(1.9	)		34.3
Net income (loss)	$	29.7		$	5.1		$	(1.6	)	$	(68.8	)	$	(35.6	)
The following table provides the reconciliation of project income to Project Adjusted EBITDA for the year ended December 31, 2013 presented under our former reportable segments:
	Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
													Corporate
Year ended December 31, 2013
Project revenues	$	227.2		$	22		$	88.6		$	214.4		$	(0.5	)	$	551.7
Segment assets		1,136.10			170.7			1,050.80			893			144.4			3,395.00
Goodwill		104.5			—			138.3			53.5			—			296.3
Capital expenditures		4.3			9.5			4.7			7.5			0.2			26.2
Project Adjusted EBITDA	$	133.1		$	11.3		$	67.2		$	77.5		$	(18.6	)		270.5
Change in fair value of derivative instruments		(19.4	)		(5.0	)		(25.9	)		—			—			(50.3	)
Depreciation and amortization		79.4			10.7			60.3			58.9			0.5			209.8
Interest, net		17			3.6			18.9			1.1			(2.1	)		38.5
Other project (income) expense		34.5			0.1			0.1			(26.0	)		(0.5	)		8.2
Project income (loss)		21.6			1.9			13.8			43.5			(16.5	)		64.3
Administration		—			—			—			—			35.2			35.2
Interest, net		—			—			—			—			104.1			104.1
Foreign exchange gain		—			—			—			—			(27.4	)		(27.4	)
Other income, net		—			—			—			—			(10.5	)		(10.5	)
Income (loss) from continuing operations before income taxes		21.6			1.9			13.8			43.5			(117.9	)		(37.1	)
Income tax benefit		—			—			—			—			(19.5	)		(19.5	)
Net income (loss) from continuing operations		21.6			1.9			13.8			43.5			(98.4	)		(17.6	)
Income (loss) from discontinued operations		—			(1.1	)		—			1.3			(6.4	)		(6.2	)
Net income (loss)	$	21.6		$	0.8		$	13.8		$	44.8		$	(104.8	)	$	(23.8	)
The table below provides information, by country, about our consolidated operations for each of the years ended December 31, 2013, 2012 and 2011 and Property, Plant & Equipment as of December 31, 2013 and 2012, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
	Revenue									Property, Plant &
										Equipment, net
	2013			2012			2011			2013			2012
United States	$	343.4		$	227.2		$	58.1		$	1,330.50		$	1,504.80
Canada		208.3			213.2			35.8			482.9			550.7
Total	$	551.7		$	440.4		$	93.9		$	1,813.40		$	2,055.50
Ontario Electricity Financial Corp ("OEFC"), San Diego Gas & Electric, and BC Hydro provided 27.7%, 14.4%, and 10.1%, respectively, of total consolidated revenues for the year ended December 31, 2013. OEFC, San Diego Gas & Electric and BC Hydro provided for 34.7%, 9.8% and 13.6% of total consolidated revenues for the year ended December 31, 2012. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the East segment. San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West segment. BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the West segment.

Related_party_transactions

Related party transactions	12 Months Ended
	Dec. 31, 2013
Related party transactions	'
Related party transactions	'
	22. Related party transactions
	Prior to December 31, 2009, Atlantic Power was managed by Atlantic Power Management, LLC (the "Manager"), which was owned by two private equity funds managed by Arclight Capital Partners, LLC ("ArcLight"). On December 31, 2009, we terminated our management agreements with the Manager and agreed to pay ArcLight an aggregate of $15.0 million, to be satisfied by a payment of $6.0 million that was made at the termination date, and additional payments of $5.0 million, $3.0 million and $1.0 million on the respective first, second and third anniversaries of the termination date. We have now paid all amounts owed to ArcLight in connection with the termination of the management agreement. As of December 31, 2012, all payments to ArcLight have been made and no further liability remains on our balance sheet.
	During 2010, we made a short-term $22.8 million loan to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing was completed. As of December 31, 2011, the project repaid the loan in full with a combination of excess proceeds from the federal stimulus cash grant after repaying the cash grant facility, funds from additional debt, and project cash flow. We received $1.6 million of interest income related to this loan in the year ended December 31, 2011.

Commitments_and_contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and contingencies.	'
Commitments and contingencies	'
	23. Commitments and contingencies
	Commitments
	Operating Lease Commitments
	We lease our office properties and equipment under operating leases expiring on various dates through 2021. Certain operating lease agreements over their lease term include provisions for scheduled rent increases. We recognize the effects of these scheduled rent increases on a straight-line basis over the lease term. Lease expense under operating leases was $1.0 million, $2.0 million and $1.0 million for the years ended December 31, 2013, 2012, and 2011, respectively. Future minimum lease commitments under operating leases for the years ending after December 31, 2013, are as follows:
	2014	$	1.6
	2015		1.8
	2016		1.7
	2017		1.6
	2018		1.5
	Thereafter		12.9
		$	21.1
	Long-Term Service Commitments
	Our projects have entered into long-term contractual arrangements to obtain maintenance services for turbine equipment expiring on various dates through 2022. As of December 31, 2013, our commitments under such outstanding agreements are estimated as follows:
	2014	$	3.5
	2015		5
	2016		5
	2017		5
	2018		5
	Thereafter		24.4
		$	47.9
	Fuel Supply and Transportation Commitments
	We have entered into long-term contractual arrangements to procure fuel and transportation services for our projects. As of December 31, 2013, our commitments under such outstanding agreements are estimated as follows:
	2014	$	83
	2015		80
	2016		73
	2017		23.4
	2018		23.6
	Thereafter		70.4
		$	353.4
	Contingencies
	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 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 was set on November 12, 2013.
	The Petitioner in the proposed class action in Quebec served and filed a motion to suspend those proceedings pending the Ontario proceedings. This motion was not granted. Nothing further has happened in the action.
	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.
	IRS Examination
	In 2011, the Internal Revenue Service ("IRS") began an examination of our federal income tax returns for the tax years ended December 31, 2007 and 2009. On April 2, 2012, the IRS issued various Notices of Proposed Adjustments. The principal area of the proposed adjustments pertain to the classification of U.S. real property in the calculation of the gain related to our 2009 conversion from the previous Income Participating Security structure to our current traditional common share structure. At December 31, 2013, the examination is before the IRS Office of Appeals.
	We continue to vigorously contest these proposed adjustments, including pursuing all administrative and judicial remedies available to us. We expect to be successful in sustaining our positions with no material impact to our financial results. We believe an adjustment, if any, would be offset by net operating loss carry forwards. No accrual has been made for any contingency related to any of the proposed adjustments as of December 31, 2013.
	Other
	In addition to the other 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. 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 December 31, 2013.

Unaudited_selected_quarterly_f

Unaudited selected quarterly financial data	12 Months Ended
	Dec. 31, 2013
Unaudited selected quarterly financial data	'
Unaudited selected quarterly financial data	'
	24. Unaudited selected quarterly financial data
	Unaudited selected quarterly financial data are as follows:
		Quarter Ended
		2013
		December 31,			September 30,			June 30,			March 31,			Total
	Project revenue	$	130.7		$	141.8		$	139.1		$	140.1		$	551.7
	Project income		7.2			4.8			20.8			31.5			64.3
	Income (loss) from continuing operations		8.2			(40.2	)		7.2			7.2			(17.6	)
	Income (loss) from discontinued operations		(0.2	)		(0.4	)		(6.0	)		0.4			(6.2	)
	Net income (loss) attributable to Atlantic Power Corporation		4.9			(41.3	)		(3.0	)		6.4			(33.0	)
	Income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	0.02		$	0.05		$	(0.23	)
	Loss per share from discontinued operations		—			—			(0.05	)		—			(0.05	)
	Income (loss) per share attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	(0.03	)	$	0.05		$	(0.28	)
	Weighted average number of common shares outstanding-basic		120.1			120			119.9			119.5			119.9
	Diluted income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	0.02		$	0.05		$	(0.23	)
	Diluted loss per share from discontinued operations		—			—			(0.05	)		—			(0.05	)
	Diluted income (loss) per share attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	(0.03	)	$	0.05		$	(0.28	)
	Weighted average number of common shares outstanding-diluted(1)		120.1			120			119.9			119.5			119.9
	-1
	The calculation excludes potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units because their impact would be anti-dilutive.
		Quarter Ended
		2012
		December 31,			September 30,			June 30,			March 31,			Total
	Project revenue	$	114		$	106.3		$	101.4		$	118.7		$	440.4
	Project (loss) income		(5.8	)		19.7			(6.9	)		(36.4	)		(29.4	)
	Loss from continuing operations		(19.7	)		(23.5	)		(20.8	)		(50.2	)		(114.2	)
	(Loss) income from discontinued operations		(34.8	)		19			18.7			11			13.9
	Net loss attributable to Atlantic Power Corporation		(58.0	)		(7.4	)		(5.1	)		(42.3	)		(112.8	)
	Loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.20	)	$	(0.22	)	$	(0.20	)	$	(0.47	)	$	(1.09	)
	Earnings (loss) per share from discontinued operations		(0.30	)		0.16			0.16			0.1			0.12
	Loss per share attributable to Atlantic Power Corporation	$	(0.50	)	$	(0.06	)	$	(0.04	)	$	(0.37	)	$	(0.97	)
	Weighted average number of common shares outstanding-basic		119.4			119			113.7			113.6			116.4
	Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.20	)	$	(0.22	)	$	(0.20	)	$	(0.47	)	$	(1.09	)
	Diluted (loss) earnings per share from discontinued operations		(0.30	)		0.16			0.16			0.1			0.12
	Diluted loss per share attributable to Atlantic Power Corporation	$	(0.50	)	$	(0.06	)	$	(0.04	)	$	(0.37	)	$	(0.97	)
	Weighted average number of common shares outstanding-diluted(1)		119.4			119			113.7			113.6			116.4
	-1
	The calculation excludes potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units because their impact would be anti-dilutive.

Guarantees

Guarantees	12 Months Ended
	Dec. 31, 2013
Guarantees	'
Guarantees	'
	25. Guarantees
	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 tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.

Consolidating_financial_inform

Consolidating financial information	12 Months Ended
	Dec. 31, 2013
Consolidating financial information	'
Consolidating financial information	'
	26. Consolidating financial information
	As of December 31, 2013 and December 31, 2012, we had $460.0 million of Senior Notes. These notes are guaranteed by certain of our 100% owned subsidiaries, or guarantor subsidiaries. These guarantees are joint and several.
	Unless otherwise noted below, each of the following 100% owned guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 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
	These guarantees were terminated upon entering into the New Senior Secured Credit Facilities on February 26, 2014. See Note 10, Long-term debt for further information.
	The following condensed consolidating financial information presents the financial information of Atlantic Power, the guarantor subsidiaries, and 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.

SCHEDULE_IIVALUATION_AND_QUALI

SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Dec. 31, 2013
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS	'
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS	'
	ATLANTIC POWER CORPORATION
	SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
	FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011
	(in millions of U.S. dollars)
		Balance at		Charged to		Charged to		Deductions		Balance at
		Beginning of		Costs and		Other Accounts				End of Period
		Period		Expenses
	Income tax valuation allowance, deducted from deferred tax assets:
	Year ended December 31, 2013	$	116	$	12.1	$	—	$	—	$	128.1
	Year ended December 31, 2012		89		20.2		6.8		—		116
	Year ended December 31, 2011		79.4		9.4		0.2		—		89

Summary_of_significant_account1

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2013
Summary of significant accounting policies	'
Principles of consolidation and basis of presentation	'
	(a)   Principles of consolidation and basis of presentation:
	The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity, through arrangements that do not involve controlling voting interests.
	We apply the standard that requires consolidation of variable interest entities ("VIEs"), for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities' economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We have determined that our equity investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation.
Cash and cash equivalents	'
	(b)   Cash and cash equivalents:
	Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of 90 days or less when purchased.
Restricted cash	'
	(c)   Restricted cash:
	Restricted cash represents cash and cash equivalents that are maintained by the projects or corporate to support payments for major maintenance costs and meet project level and corporate contractual debt obligations.
Deferred financing costs	'
	(d)   Deferred financing costs:
	Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective interest method over the term of the related debt which range from 5 to 28 years. The net carrying amount of deferred financing costs recorded in other assets on the consolidated balance sheets was $41.7 million and $47.2 million at December 31, 2013 and 2012, respectively. Amortization expense for the years ended December 31, 2013, 2012, and 2011 was $8.0 million, $4.4 million, and $1.3 million, respectively.
Inventory	'
	(e)   Inventory:
	Inventory represents small parts and other consumables and fuel, the majority of which is consumed by our projects in provision of their services, and are valued at the lower of cost or net realizable value. Cost includes the purchase price, transportation costs and other costs to bring the inventories to their present location and condition. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs.
Property, plant and equipment	'
	(f)    Property, plant and equipment:
	Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset, up to 45 years. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in the consolidated statements of operations.
Project development costs and capitalized interest	'
	(g)   Project development costs and capitalized interest:
	Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, obtaining a PPA.
	Interest incurred on funds borrowed to finance capital projects is capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2013, 2012, and 2011 was $1.9 million, $17.0 million, and $3.0 million, respectively.
	When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
Other intangible assets	'
	(h)   Other intangible assets:
	Other intangible assets include PPAs and fuel supply agreements at our projects. PPAs are valued at the time of acquisition based on the contract prices under the PPAs compared to projected market prices. Fuel supply agreements are valued at the time of acquisition based on the contract prices under the fuel supply agreement compared to projected market prices. The balances are presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement.
Investments accounted for by the equity method	'
	(i)    Investments accounted for by the equity method:
	We make investments in entities that own power producing assets with the objective of generating accretive cash flow that is available to be distributed to our shareholders. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents us from exercising a controlling influence over the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with 50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships and limited liability companies with greater than 5% ownership because our influence over the investment's operating and financial policies is considered to be more than minor.
	Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings of unconsolidated affiliates. The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the affiliates' power producing assets and are classified as cash flows from operating activities in the consolidated statements of cash flows. We record the return of our investments in equity investees as cash flows from investing activities. Cash flows from equity investees are considered a return of capital when distributions are generated from proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets.
Impairment of long-lived assets, non-amortizing intangible assets and equity method investments	'
	(j)    Impairment of long-lived assets, non-amortizing intangible assets and equity method investments:
	Long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds its fair value.
	Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. We also review a project for impairment and perform a two-step test at the earlier of executing a new PPA (or other arrangement) or six months prior to the expiration of an existing PPA. Factors such as the business climate, including current energy and market conditions, environmental regulation, the condition of assets, and the ability to secure new PPAs are considered when evaluating long-lived assets for impairment. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment or, where applicable, estimated sales proceeds that are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value.
Goodwill	'
	(k)   Goodwill:
	Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the business combination.
	Goodwill is not amortized and is tested for impairment, annually in the fourth quarter, or more frequently if events or changes in circumstances indicate that the asset might be impaired. In September 2011, the Financial Accounting Standards Board ("FASB") issued ASU 2011-08 "Intangibles—Goodwill and Other." This guidance on testing goodwill provides the option to first perform a qualitative assessment ("step zero") to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If we determine that this is the case, we are required to perform a two-step goodwill impairment test, as described below, to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized for that reporting unit (if any). If we determine that the fair value of a reporting unit is not less than its carrying amount, the two-step goodwill impairment test is not required.
	In our test, we first perform step zero to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (i.e. more than 50%) that the fair value of a reporting unit 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 the qualitative assessment determines that an impairment is more likely than not, then we perform a two-step quantitative impairment test. In the first step of the quantitative analysis, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired and the second step of the impairment test is unnecessary.
	The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit's goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination, using the fair value of the reporting unit as if it were the purchase price. When the carrying amount of reporting unit goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess and is recorded in the consolidated statements of operations.
Discontinued operations	'
	(l)    Discontinued operations:
	Long-lived assets or disposal groups are classified as discontinued operations when all of the required criteria are met. Criteria include, among others, existence of a qualified plan to dispose of an asset or disposal group, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management. In addition, upon completion of the transaction, the operations and cash flows of the disposal group must be eliminated from our ongoing operations, and the disposal group must not have any significant continuing involvement with us. Discontinued operations are reported at the lower of the asset's carrying amount or fair value less cost to sell.
Derivative financial instruments	'
	(m)  Derivative financial instruments:
	We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a major production cost. We do not enter into derivative financial instruments for trading or speculative purposes. Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales in the ordinary course of conducting business. This exception applies when we have the ability to, and it is probable that we will deliver or take delivery of the underlying physical commodity.
	We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Derivatives accounted for as hedges are recorded at fair value in the balance sheet. Unrealized gains or losses on derivatives designated as a hedge are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings.
	Derivative financial instruments not designated as a hedge are measured at fair value with changes in fair value recorded in the consolidated statements of operations. The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument:
	Derivative financial instrument	Classification of changes in fair value		Classification of cash settlements
	Natural gas swaps	Changes in fair value of derivative instrument		Fuel expense
	Gas purchase agreements	Changes in fair value of derivative instrument		Fuel expense
	Interest rate swaps	Changes in fair value of derivative instrument		Interest expense
	Foreign currency forward contract	Foreign exchange (gain) loss		Foreign exchange (gain) loss
Income taxes	'
	(n)   Income taxes:
	Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 14 for more information.
Revenue recognition	'
	(o)   Revenue recognition:
	We recognize energy sales revenue on a gross basis when electricity and steam are delivered under the terms of the related contracts. PPAs, steam purchase arrangements and energy services agreements are long-term contracts to sell power and steam on a predetermined basis.
	Energy—Energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in our consolidated statements of operations.
	Capacity—Capacity payments under the PPAs are recognized as the lesser of (1) the amount billable under the PPA or (2) an amount determined by the kilowatt hours made available during the period multiplied by the estimated average revenue per kilowatt hour over the term of the PPA.
Power purchase arrangements containing a lease	'
	(p)   Power purchase arrangements containing a lease:
	We have entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the project's property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.
	Finance income related to leases or arrangements accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income (loss) over the lease term.
	For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of energy revenue. When energy is delivered, we recognize lease income in energy revenue.
Foreign currency translation and transaction gains and losses	'
	(q)   Foreign currency translation and transaction gains and losses:
	The local currency is the functional currency of our U.S. and Canadian projects. Our reporting currency is the U.S. dollar. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of our statements of operations for the period, but are accumulated and reported as a separate component of shareholders' equity until sale of the net investment in the project takes place. Foreign currency transaction gains or losses are reported within foreign exchange (gain) loss in our statements of operations.
Equity compensation plans	'
	(r)   Equity compensation plans:
	The officers and certain other employees are eligible to participate in the Long-Term Incentive Plan ("LTIP"). Some of the notional units that vest are based, in part, on certain financial performance metrics and the total shareholder return of Atlantic Power compared to a group of peer companies. In addition, vesting of certain notional units for officers of Atlantic Power occurs on a three-year cliff basis as opposed to ratable vesting over three years for non-officers. During April 2012, the Compensation Committee of the Board approved certain changes to the award process and vesting criteria of the LTIP, and on April 11, 2013, the Board adopted the Fifth Amended and Restated Atlantic Power Holdings, Inc. LTIP (the "Fifth Amended and Restated LTIP"), which reflected such changes. Awards to senior officers under the Fifth Amended and Restated LTIP are made annually based on the performance over the applicable fiscal year and will vest as to one third over each of the three years following the year of the award. Notional shares granted prior to the amendment are still subject to three-year cliff vesting.
	Vested notional units are expected to be redeemed one-third in cash and two-thirds in shares of our common stock. Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date or if we do not meet certain ongoing cash flow performance targets.
	For awards that are subject to a performance-based vesting condition, the final number of notional units for officers that will vest, if any, at the end of the three-year vesting period is based on our achievement of certain financial performance metrics and meeting target levels of relative total shareholder return, which is the change in the value of an investment in our common stock, including reinvestment of dividends, compared to that of a peer group of companies during the performance period. The total number of notional units vesting will range from zero up to a maximum 150% of the number of notional units in the executives' accounts on the vesting date for that award, depending on the level of achievement of relative total shareholder return during the measurement period.
	Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. The fair value of awards granted under the LTIP with market vesting conditions is based upon a Monte Carlo simulation model on the grant date. Compensation expense is recognized regardless of the relative total shareholder return performance, provided that the LTIP participant remains employed by Atlantic Power.
Asset retirement obligations	'
	(s)   Asset retirement obligations:
	The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss.
Pensions	'
	(t)    Pensions:
	We offer pension benefits to certain employees through a defined benefit pension plan. We recognize the funded status of our defined benefit plan in the consolidated balance sheet in other long-term liabilities and record an offset to other comprehensive income (loss). In addition, we also recognize on an after-tax basis, as a component of other comprehensive income (loss), gains and losses as well as all prior service costs that have not been included as part of our net periodic benefit cost. The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Our actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of our pension obligation or expense recorded.
Business combinations	'
	(u)   Business combinations:
	We account for our business combinations in accordance with the acquisition method of accounting, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
Concentration of credit risk	'
	(v)   Concentration of credit risk:
	The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to the credit worthiness and payment history of our customers. See Note 21, Segment and geographic information, for a further discussion of customer concentrations.
Use of estimates	'
	(w)  Use of estimates:
	The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and the allocation of taxable income and losses, tax credits and cash distributions using the hypothetical liquidation book value ("HLBV") method. 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. 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.
Federal grants	'
	(x)   Federal grants:
	Certain projects are eligible to receive grants and similar government incentives for the construction of renewable energy facilities. Proceeds from these grants reduce the basis of the corresponding asset balance when the cash is received.
Allocation of net income or losses to certain investors using HLBV	'
	(y)   Allocation of net income or losses to certain investors using HLBV:
	For consolidated investments with flip structures that allocate taxable income and losses, tax credits and cash distributions under allocation provisions of agreements with third-party investors, net income or loss is allocated to third-party investors for accounting purposes using the hypothetical liquidation book value method. HLBV is a balance sheet oriented approach that calculates the change in the claims of each partner on the net assets of the investment at the beginning and end of each period. Each partner's claim is equal to the amount each party would receive or pay if the net assets of the investment were to liquidate at book value and the resulting cash was then distributed to investors in accordance with their respective liquidation preferences. We report the net income or loss attributable to the third-party investors as income (loss) attributable to noncontrolling interests in the consolidated statements of operations.
Recently issued accounting standards	'
	(z)   Recently issued accounting standards:
	Adopted
	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.
	The changes in accumulated other comprehensive income (loss) by component were as follows:
		Year Ended December 31,
		2013			2012			2011
	Foreign currency translation
	Balance at beginning of period	$	12.6		$	(3.3	)	$	—
	Other comprehensive income (loss):
	Foreign currency translation adjustments(1)		(34.8	)		15.9			(3.3	)
	Balance at end of period	$	(22.2	)	$	12.6		$	(3.3	)
	Pension
	Balance at beginning of period	$	(1.8	)	$	(0.5	)	$	—
	Other comprehensive income (loss):
	Unrecognized net actuarial gain (loss)		2.4			(2.1	)		(0.8	)
	Tax benefit (expense)		(0.7	)		0.8			0.3
	Total Other comprehensive income (loss) before reclassifications, net of tax		1.7			(1.3	)		(0.5	)
	Amortization of net actuarial gain(2)		(0.4	)		—			—
	Tax benefit (expense)(5)		0.1			—			—
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		(0.3	)		—			—
	Total Other comprehensive income (loss)		1.4			(1.3	)		(0.5	)
	Balance at end of period	$	(0.4	)	$	(1.8	)	$	(0.5	)
	Cash flow hedges
	Balance at beginning of period	$	(1.4	)	$	(1.4	)	$	0.2
	Other comprehensive income (loss):
	Net change from periodic revaluations		1.2			(1.5	)		(4.4	)
	Tax benefit (expense)		(0.5	)		0.6			1.8
	Total Other comprehensive income (loss) before reclassifications, net of tax		0.7			(0.9	)		(2.6	)
	Net amount reclassified to earnings:
	Interest rate swaps(3)		1.7			1.9			2.3
	Fuel commodity swaps(4)		(0.2	)		(0.4	)		(0.7	)
	Sub-total		1.5			1.5			1.6
	Tax benefit(5)		(0.6	)		(0.6	)		(0.6	)
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(6)		0.9			0.9			1
	Total Other comprehensive income (loss)		1.6			—			(1.6	)
	Balance at end of period	$	0.2		$	(1.4	)	$	(1.4	)
	-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 Administration on the accompanying Consolidated Statements of Operations.
	-3
	This amount was included in Interest, net on the accompanying Consolidated Statements of Operations.
	-4
	These amounts were included in Fuel on the accompanying Consolidated Statements of Operations.
	-5
	These amounts were included in Income tax expense (benefit) on the accompanying Consolidated Statements of Operations.
	-6
	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 Consolidated Statements of Operations in the line items indicated in footnotes 2 through 5.
	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.
	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, 2012, we adopted changes issued by the FASB to conform existing guidance regarding fair value measurement and disclosure between 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 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 our consolidated financial statements.
	On January 1, 2012, we adopted changes issued by the FASB to the presentation of comprehensive income (loss). These changes give an entity the option to present the total of comprehensive income (loss), the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income (loss) or in two separate but consecutive statements; the option to present components of other comprehensive income (loss) as part of the statement of changes in shareholders' equity was eliminated. The items that must be reported in other comprehensive income (loss) or when an item of other comprehensive income (loss) must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. We elected to present the two-statement option. Other than the change in presentation, the adoption of these changes had no impact on our consolidated financial statements.
	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 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. 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.
	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.

Summary_of_significant_account2

Summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of significant accounting policies	'
Summary of derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument	'
	Derivative financial instrument	Classification of changes in fair value		Classification of cash settlements
	Natural gas swaps	Changes in fair value of derivative instrument		Fuel expense
	Gas purchase agreements	Changes in fair value of derivative instrument		Fuel expense
	Interest rate swaps	Changes in fair value of derivative instrument		Interest expense
	Foreign currency forward contract	Foreign exchange (gain) loss		Foreign exchange (gain) loss
Schedule of changes in accumulated other comprehensive income (loss) by component	'
		Year Ended December 31,
		2013			2012			2011
	Foreign currency translation
	Balance at beginning of period	$	12.6		$	(3.3	)	$	—
	Other comprehensive income (loss):
	Foreign currency translation adjustments(1)		(34.8	)		15.9			(3.3	)
	Balance at end of period	$	(22.2	)	$	12.6		$	(3.3	)
	Pension
	Balance at beginning of period	$	(1.8	)	$	(0.5	)	$	—
	Other comprehensive income (loss):
	Unrecognized net actuarial gain (loss)		2.4			(2.1	)		(0.8	)
	Tax benefit (expense)		(0.7	)		0.8			0.3
	Total Other comprehensive income (loss) before reclassifications, net of tax		1.7			(1.3	)		(0.5	)
	Amortization of net actuarial gain(2)		(0.4	)		—			—
	Tax benefit (expense)(5)		0.1			—			—
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(5)		(0.3	)		—			—
	Total Other comprehensive income (loss)		1.4			(1.3	)		(0.5	)
	Balance at end of period	$	(0.4	)	$	(1.8	)	$	(0.5	)
	Cash flow hedges
	Balance at beginning of period	$	(1.4	)	$	(1.4	)	$	0.2
	Other comprehensive income (loss):
	Net change from periodic revaluations		1.2			(1.5	)		(4.4	)
	Tax benefit (expense)		(0.5	)		0.6			1.8
	Total Other comprehensive income (loss) before reclassifications, net of tax		0.7			(0.9	)		(2.6	)
	Net amount reclassified to earnings:
	Interest rate swaps(3)		1.7			1.9			2.3
	Fuel commodity swaps(4)		(0.2	)		(0.4	)		(0.7	)
	Sub-total		1.5			1.5			1.6
	Tax benefit(5)		(0.6	)		(0.6	)		(0.6	)
	Total amount reclassified from Accumulated other comprehensive loss, net of tax(6)		0.9			0.9			1
	Total Other comprehensive income (loss)		1.6			—			(1.6	)
	Balance at end of period	$	0.2		$	(1.4	)	$	(1.4	)
	-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 Administration on the accompanying Consolidated Statements of Operations.
	-3
	This amount was included in Interest, net on the accompanying Consolidated Statements of Operations.
	-4
	These amounts were included in Fuel on the accompanying Consolidated Statements of Operations.
	-5
	These amounts were included in Income tax expense (benefit) on the accompanying Consolidated Statements of Operations.
	-6
	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 Consolidated Statements of Operations in the line items indicated in footnotes 2 through 5.

Acquisitions_and_divestments_T

Acquisitions and divestments (Tables)	12 Months Ended
	Dec. 31, 2013
Ridgeline	'
Acquisition and divestments	'
Schedule of allocation of the purchase price	'
	Fair value of consideration transferred:
	Cash	$	81.3
	Other items to be allocated to identifiable assets acquired and liabilities assumed:
	Fair value of our investment in Rockland at the acquisition date		12.1
	Loss recognized on the step acquisition		(7.4	)
	Total purchase price	$	86
	Final purchase price allocation
	Cash	$	1
	Working capital		(8.1	)
	Property, plant, and equipment		373.9
	Deferred tax asset		9.6
	Other long-term assets		36
	Long-term debt		(295.5	)
	Interest rate swaps		(21.6	)
	Other long-term liabilities		(1.3	)
	Minority interest		(8.0	)
	Total identifiable net assets	$	86
Partnership	'
Acquisition and divestments	'
Schedule of allocation of the purchase price	'
	Fair value of consideration transferred:
	Cash	$	601.8
	Equity		407.4
	Total purchase price	$	1,009.20
	Final purchase price allocation
	Working capital	$	38
	Property, plant, and equipment		1,024.00
	Intangibles		528.5
	Other long-term assets		224.3
	Long-term debt		(621.6	)
	Other long-term liabilities		(129.3	)
	Deferred tax liability		(164.5	)
	Total identifiable net assets		899.4
	Preferred shares		(221.3	)
	Goodwill		331.1
	Total purchase price		1,009.20
	Less cash acquired		(22.7	)
	Cash paid, net of cash acquired	$	986.5
Schedule of pro forma results of operations	'
		Unaudited
		Years ended
		December 31,
		2011			2010
	Total project revenue	$	694.2		$	670
	Net loss attributable to Atlantic Power Corporation		(95.8	)		(2.5	)
	Net loss per share attributable to Atlantic Power Corporation shareholders:
	Basic	$	(0.85	)	$	(0.02	)
	Diluted	$	(0.85	)	$	(0.02	)

Equity_method_investments_in_u1

Equity method investments in unconsolidated affiliates (Tables)	12 Months Ended
	Dec. 31, 2013
Equity method investments in unconsolidated affiliates	'
Schedule of equity method investments	'
					Carrying value as of
		Percentage of			December 31.
		Ownership as of
	Entity name	December 31, 2013			2013			2012
	Frederickson		50	%	$	153.9		$	167.7
	Orlando Cogen, LP		50	%		14.3			19.9
	Onondaga Rewables, LLC		50	%		—			0.2
	Koma Kulshan Associates		49.8	%		5.8			6.4
	Chambers Cogen, LP		40	%		153.7			154.3
	Delta-Person, LP		40	%		—			—
	Idaho Wind Partners 1, LLC		27.6	%		33.2			34.7
	Selkirk Cogen Partners, LP		18.5	%		24.4			33.7
	Goshen North		12.5	%		9			9
	Gregory Power Partners, LP		—			—			2.8
	Total				$	394.3		$	428.7
Equity (deficit) in earnings (loss) of equity method investments	'
		Year Ended December 31,
	Entity name	2013			2012			2011
	Chambers Cogen, LP	$	9.6		$	17.1		$	7.7
	Orlando Cogen, LP		3.3			3.2			0.9
	Koma Kulshan Associates		0.3			0.5			0.5
	Frederickson		2.1			0.9			0.4
	Idaho Wind Partners 1, LLC		(0.3	)		(0.2	)		(1.6	)
	Selkirk Cogen Partners, LP		8.7			7.6			(0.4	)
	Goshen North		1.4			—			—
	Gregory Power Partners, LP(1)		1.6			(0.7	)		0.5
	Onondaga Rewables, LLC		(0.3	)		(0.4	)		(1.8	)
	Rockland Wind Farm(2)		—			(8.0	)		—
	Other		0.5			(4.8	)		0.2
	Total		26.9			15.2			6.4
	Distributions from equity method investments		(40.9	)		(38.4	)		(21.9	)
	Deficit in earnings (loss) of equity method investments, net of distributions	$	(14.0	)	$	(23.2	)	$	(15.5	)
	-1
	We sold Gregory in August 2013, resulting in a gain $30.4 million, which is recorded in gain on sale of equity investments in the consolidated statements of operations for the year ended December 31, 2013.
	-2
	Due to an ownership change from 30% to 50% as part of the Ridgeline acquisition during the fourth quarter of 2012, Rockland Wind Farm was consolidated as of December 31, 2012.
Summarized financial position information	'
		2013			2012			2011
	Assets
	Current assets
	Chambers Cogen, LP	$	11.8		$	16.1		$	9.9
	Selkirk Cogen Partners, LP		12.9			12.9			15.9
	Other		24.6			32			22.3
	Non-current assets
	Chambers Cogen, LP		224			235.2			245.8
	Selkirk Cogen Partners, LP		14.1			26			47.7
	Other		286.6			322.3			359.1
		$	574		$	644.5		$	700.7
	Liabilities
	Current liabilities
	Chambers Cogen, LP	$	4.4		$	15.2		$	16
	Selkirk Cogen Partners, LP		2.3			4.8			14.7
	Other		13.9			16.4			19.1
	Non-current liabilities
	Chambers Cogen, LP		77.7			81.8			96
	Selkirk Cogen Partners, LP		0.3			0.3			1.5
	Other		81.1			97.3			79
		$	179.7		$	215.8		$	226.3
	Operating results	2013			2012			2011
	Revenue
	Chambers Cogen, LP	$	52.7		$	58.1		$	49.3
	Selkirk Cogen Partners, LP		50.5			48.7			54.6
	Other		101.2			109.8			91.8
			204.4			216.6			195.7
	Project expenses
	Chambers Cogen, LP		40.6			39.1			39.4
	Selkirk Cogen Partners, LP		40.3			42.4			49.6
	Other		88.9			92.7			85.4
			169.8			174.2			174.4
	Project other income (expense)
	Chambers Cogen, LP		(2.5	)		(1.9	)		(2.2	)
	Selkirk Cogen Partners, LP		(1.5	)		1.3			(5.4	)
	Other		(3.7	)		(26.6	)		(7.3	)
			(7.7	)		(27.2	)		(14.9	)
	Project income (loss)
	Chambers Cogen, LP	$	9.6		$	17.1		$	7.7
	Selkirk Cogen Partners, LP		8.7			7.6			(0.4	)
	Other		8.6			(9.5	)		(0.9	)
			26.9			15.2			6.4
Summarized operating results information	'
	Operating results	2013			2012			2011
	Revenue
	Chambers Cogen, LP	$	52.7		$	58.1		$	49.3
	Selkirk Cogen Partners, LP		50.5			48.7			54.6
	Other		101.2			109.8			91.8
			204.4			216.6			195.7
	Project expenses
	Chambers Cogen, LP		40.6			39.1			39.4
	Selkirk Cogen Partners, LP		40.3			42.4			49.6
	Other		88.9			92.7			85.4
			169.8			174.2			174.4
	Project other income (expense)
	Chambers Cogen, LP		(2.5	)		(1.9	)		(2.2	)
	Selkirk Cogen Partners, LP		(1.5	)		1.3			(5.4	)
	Other		(3.7	)		(26.6	)		(7.3	)
			(7.7	)		(27.2	)		(14.9	)
	Project income (loss)
	Chambers Cogen, LP	$	9.6		$	17.1		$	7.7
	Selkirk Cogen Partners, LP		8.7			7.6			(0.4	)
	Other		8.6			(9.5	)		(0.9	)
			26.9			15.2			6.4

Inventory_Tables

Inventory (Tables)	12 Months Ended
	Dec. 31, 2013
Inventory	'
Schedule of inventories	'
		December 31,
		2013		2012
	Parts and other consumables	$	11.3	$	8.6
	Fuel		4.7		8.3
	Total inventory	$	16	$	16.9

Property_plant_and_equipment_T

Property, plant and equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, plant and equipment	'
Schedule of property, plant and equipment	'
		December 31,			December 31,			Depreciable
		2013			2012			Lives
	Land	$	5.9		$	7.3
	Office equipment, machinery and other		3.3			2.9		3 - 10 years
	Leasehold improvements		0.4			0.4		7 - 15 years
	Asset retirement obligation		34.8			35.8		1 - 42 years
	Plant in service		1,938.40			1,895.00		1 - 45 years
	Construction in progress		5.7			193.7
			1,988.50			2,135.10
	Less accumulated depreciation		(175.1	)		(79.6	)
		$	1,813.40		$	2,055.50

Goodwill_Tables

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill	'
Schedule of changes in the carrying amount of goodwill	'
		East			West			Wind		Un-allocated			Total
										corporate
	Balance at December 31, 2011	$	138.6		$	201.5		$	—	$	3.5		$	343.6
	Reclass to assets held for sale		—			(8.9	)		—		—			(8.9	)
	Balance at December 31, 2012		138.6			192.6			—		3.5			334.7
	Impairment of goodwill		(30.8	)		(4.1	)		—		(3.5	)		(38.4	)
	Balance at December 31, 2013	$	107.8		$	188.5		$	—	$	—		$	296.3

Power_purchase_agreements_and_1

Power purchase agreements and other intangible assets and liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Power purchase agreements and other intangible assets and liabilities.	'
Schedule of components of intangible assets subject to amortization	'
		Other Intangible Assets, Net
		Power			Development			Total
		Purchase			Costs
		Agreements
	Gross balances, December 31, 2013	$	597.4		$	4.8		$	602.2
	Less: accumulated amortization		(139.8	)		(0.3	)		(140.1	)
	Foreign currency translation adjustment		(10.6	)		—			(10.6	)
	Net carrying amount, December 31, 2013	$	447		$	4.5		$	451.5
		Other Intangible Assets, Net
		Power			Development			Total
		Purchase			Costs
		Agreements
	Gross balances, December 31, 2012	$	590.9		$	6.2		$	597.1
	Less: accumulated amortization		(76.9	)		—			(76.9	)
	Foreign currency translation adjustment		4.7			—			4.7
	Net carrying amount, December 31, 2012	$	518.7		$	6.2		$	524.9
		Power Purchase and Fuel Supply
		Agreement Liabilities, Net
		Power			Fuel			Total
		Purchase			Supply
		Agreements			Agreements
	Gross balances, December 31, 2013	$	(35.9	)	$	(12.6	)	$	(48.5	)
	Less: accumulated amortization		5.3			2.5			7.8
	Foreign currency translation adjustment		2			—			2
	Net carrying amount, December 31, 2013	$	(28.6	)	$	(10.1	)	$	(38.7	)
		Power Purchase and Fuel Supply
		Agreement Liabilities, Net
		Power			Fuel			Total
		Purchase			Supply
		Agreements			Agreements
	Gross balances, December 31, 2012	$	(35.3	)	$	(12.6	)	$	(47.9	)
	Less: accumulated amortization		2.9			1.6			4.5
	Foreign currency translation adjustment		(0.6	)		—			(0.6	)
	Net carrying amount, December 31, 2012	$	(33.0	)	$	(11.0	)	$	(44.0	)
Schedule of amortization expense of intangible assets	'
		2013			2012			2011
	Power purchase agreements	$	60.8		$	59.5		$	11.6
	Fuel supply agreements		(1.2	)		(1.2	)		(1.4	)
	Total amortization expense	$	59.6		$	58.3		$	10.2
Schedule of estimated future amortization expense for the next five years	'
	Year Ended December 31,	Power Purchase			Fuel Supply
		Agreements			Agreements
	2014	$	58.4		$	(1.2	)
	2015		55			(1.2	)
	2016		55			(1.2	)
	2017		55.1			(1.2	)
	2018		47.3			(1.2	)
Schedule of weighted average remaining amortization period related to the entity's intangible assets	'
	As of December 31, 2013	Power Purchase			Fuel Supply
		Agreements			Agreements
	(in years)
	Weighted average remaining amortization period		9			9

Other_longterm_liabilities_Tab

Other long-term liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Other long-term liabilities	'
Schedule of other long-term liabilities	'
		2013			2012
	Asset retirement obligations	$	57.7		$	57.8
	Net pension liability		0.8			4.8
	Deferred revenue		4			4.9
	Other		2.9			3.9
		$	65.4		$	71.4
Schedule of asset retirement obligations in acquisition of CPILP	'
		2013
	Asset retirement obligations beginning of year	$	57.8
	Accretion of asset retirement obligations		1.6
	Translation adjustments		(1.7	)
	Asset retirement obligations, end of year	$	57.7

Longterm_debt_Tables

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-term debt	'
Schedule of long-term debt	'
		December 31,			December 31,			Interest Rate
		2013			2012
	Recourse Debt:
	Senior unsecured notes, due 2018	$	460		$	460		9.00%
	Senior unsecured notes, due June 2036 (Cdn$210.0)		197.4			211.1		6.00%
	Senior unsecured notes, due July 2014(3)		190			190		5.90%
	Series A senior unsecured notes, due August 2015(3)		150			150		5.90%
	Series B senior unsecured notes, due August 2017(3)		75			75		6.00%
	Non-Recourse Debt:
	Epsilon Power Partners term facility, due 2019		30.5			33.5		7.40%
	Cadillac term loan, due 2025		35.4			37.8		6.0% - 8.0%
	Piedmont construction loan, due 2014(1)		76.6			127.4		Libor plus 3.5%
	Meadow Creek term loan, due 2024(2)		169.8			208.7		2.9% - 5.6%
	Rockland term loan, due 2027		85.3			86.5		6.40%
	Other long-term debt		1			0.3		5.5% - 6.7%
	Less: current maturities		(216.2	)		(121.2	)
	Total long-term debt	$	1,254.80		$	1,459.10
Schedule of current maturities	'
		December 31,			December 31,			Interest Rate
		2013			2012
	Current Maturities:
	Senior unsecured notes, due July 2014	$	190		$	—		5.90%
	Epsilon Power Partners term facility, due 2019		5			3		7.40%
	Cadillac term loan, due 2025		2			2.4		6.0% - 8.0%
	Piedmont construction loan, due 2014(1)		12.6			55.1		Libor plus 3.5%
	Meadow Creek term loan, due 2024(2)		4.9			59.5		2.9% - 5.6%
	Rockland term loan, due 2027		1.5			1.2		6.40%
	Other short-term debt		0.2			—		5.5 - 6.7%
	Total current maturities	$	216.2		$	121.2
	-1
	The terms of the Piedmont project-level debt financing included a $51.0 million bridge loan and an $82.0 million construction loan ($76.6 million at December 31, 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. On February 14, 2014, we paid down $8.1 million of principal on the construction loan and converted the remaining $68.5 million to a term loan due August 2018 with an interest rate of LIBOR plus an applicable margin ranging from 3.5% to 4.0%.
	-2
	The terms of the Meadow Creek project-level debt financing included a $56.5 million cash grant loan and a $169.8 million term 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 us to cover the shortfall from lower grant-eligible costs than anticipated, primarily as a result of a lower project cost as compared to budget.
	-3
	The Curtis Palmer Notes, Series A senior guaranteed notes due August 2015 and Series B senior guaranteed notes due August 2017 were retired on February 26, 2014 with a portion of the proceeds from the New Senior Secured Credit Facilities described below.
Schedule of principal payments on the maturities of debt due in next five years	'
	2014	$	216.2
	2015		170.6
	2016		19
	2017		96.5
	2018		529.5
	Thereafter		439.2
		$	1,471.00

Convertible_debentures_Tables

Convertible debentures (Tables)	12 Months Ended
	Dec. 31, 2013
Convertible debentures	'
Schedule of outstanding convertible debentures	'
		6.50%			6.25%			5.60%			5.75%		6.00%			Total
		Debentures			Debentures			Debentures			Debentures		Debentures
		due			due			due			due		due
		Oct-14			Mar-17			Jun-17			Jun-19		Dec-19
	Balance at December 31, 2011	$	44.1		$	66.3		$	79.2		$	—	$	—		$	189.6
	Issuance of convertible debentures		—			—			—			130		100.6			230.6
	Foreign exchange (gain) loss		1			1.5			1.8			—		(0.3	)		4
	Balance at December 31, 2012	$	45.1		$	67.8		$	81		$	130	$	100.3		$	424.2
	Foreign exchange (gain) loss		(3.0	)		(4.4	)		(5.3	)		—		(6.3	)		(19.0	)
	Balance at December 31, 2013	$	42.1		$	63.4		$	75.7		$	130	$	94		$	405.2

Fair_value_of_financial_instru1

Fair value of financial instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair value of financial instruments	'
Schedule of estimated carrying values and fair values of financial instruments	'
		December 31,
		2013				2012
		Carrying		Fair		Carrying		Fair
		Amount		Value		Amount		Value
	Cash and cash equivalents	$	158.6	$	158.6	$	60.2	$	60.2
	Restricted cash		114.2		114.2		28.6		28.6
	Derivative assets current		0.2		0.2		9.5		9.5
	Derivative assets non-current		13		13		11.1		11.1
	Derivative liabilities current		28.5		28.5		33		33
	Derivative liabilities non-current		76.1		76.1		118.1		118.1
	Revolving credit facility and long-term debt, including current portion		1,471.00		1,435.20		1,647.30		1,701.80
	Convertible debentures		405.2		281.1		424.2		416.7
Schedule of recurring measurements of fair value hierarchy of financial assets and liabilities	'
		December 31, 2013
		Level 1		Level 2		Level 3		Total
	Assets:
	Cash and cash equivalents	$	158.6	$	—	$	—	$	158.6
	Restricted cash		114.2		—		—		114.2
	Derivative instruments asset		—		13.2		—		13.2
	Total	$	272.8	$	13.2	$	—	$	286
	Liabilities:
	Derivative instruments liability	$	—	$	104.6	$	—	$	104.6
	Total	$	—	$	104.6	$	—	$	104.6
		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

Recovered_Sheet1

Accounting for Derivative instruments and hedging activities (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting for derivative instruments and hedging activities	'
Schedule of notional volumes of forecasted transactions	'
		Units		December 31,			December 31,
				2013			2012
	Natural gas swaps	Natural Gas (Mmbtu)			5.6			10.6
	Gas purchase agreements	Natural Gas (Gigajoules)			41.1			49.8
	Interest rate swaps	Interest (US$)			161.2			172
	Currency forwards	Cdn$			34.9			176.6
Schedule of fair value of derivative instruments	'
		December 31, 2013
		Derivative			Derivative
		Assets			Liabilities
	Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—		$	1.3
	Interest rate swaps long-term		—			2.6
	Total derivative instruments designated as cash flow hedges		—			3.9
	Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—			7.3
	Interest rate swaps long-term		11.5			8.1
	Foreign currency forward contracts current		0.5			0.7
	Foreign currency forward contracts long-term		1.2			—
	Natural gas swaps current		0.3			1.3
	Natural gas swaps long-term		—			3.5
	Gas purchase agreements current		0.2			18.4
	Gas purchase agreements long-term		—			61.9
	Total derivative instruments not designated as cash flow hedges		13.7			101.2
	Total derivative instruments	$	13.7		$	105.1
		December 31, 2012
		Derivative			Derivative
		Assets			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			—
	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
Schedule of changes in OCI attributable to derivative financial instruments	'
	For the year ended December 31, 2013	Interest			Natural			Total
		Rate			Gas
		Swaps			Swaps
	Accumulated OCI balance at January 1, 2013	$	(1.5	)	$	0.1		$	(1.4	)
	Change in fair value of cash flow hedges		0.7			—			0.7
	Realized from OCI during the period		1			(0.1	)		0.9
	Accumulated OCI balance at December 31, 2013	$	0.2		$	—		$	0.2
	Gains expected to be realized from OCI in the next 12 months, net of $0.6 tax	$	1		$	—		$	1
	For the year ended December 31, 2012	Interest			Natural			Total
		Rate			Gas
		Swaps			Swaps
	Accumulated OCI balance at January 1, 2012	$	(1.7	)	$	0.3		$	(1.4	)
	Change in fair value of cash flow hedges		(0.9	)		—			(0.9	)
	Realized from OCI during the period		1.1			(0.2	)		0.9
	Accumulated OCI balance at December 31, 2012	$	(1.5	)	$	0.1		$	(1.4	)
	For the year ended December 31, 2011	Interest			Natural			Total
		Rate			Gas
		Swaps			Swaps
	Accumulated OCI balance at January 1, 2011	$	(0.4	)	$	0.6		$	0.2
	Change in fair value of cash flow hedges		(2.6	)		—			(2.6	)
	Realized from OCI during the period		1.4			(0.4	)		1
	Accumulated OCI balance at December 31, 2011	$	(1.6	)	$	0.2		$	(1.4	)
Summary of realized (gains) and losses for derivative instruments not designated as cash flow hedges	'
				Year ended December 31,
		Classification of (gain)
		loss recognized in income		2013			2012			2011
	Gas purchase agreements	Fuel		$	56.5		$	43.5		$	—
	Interest rate swaps	Interest, net			9.9			4.6			4.2
	Foreign currency forwards	Foreign exchange (gain) loss			(14.4	)		(18.5	)		5.2
Summary of the unrealized gains and (losses) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges	'
				Year ended December 31,
		Classification of (gain) loss
		recognized in income		2013			2012			2011
	Natural gas swaps	Change in fair value of derivatives		$	(0.7	)	$	(1.2	)	$	(2.4	)
	Gas purchase agreements	Change in fair value of derivatives			19.2			(57.0	)		—
	Interest rate swaps	Change in fair value of derivatives			31			(1.1	)		(12.2	)
				$	49.5		$	(59.3	)	$	(14.6	)
	Foreign currency forwards	Foreign exchange loss		$	19.4		$	12		$	14.2

Income_taxes_Tables

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income taxes	'
Schedule of components of income tax expenses (benefit)	'
		Year ended December 31
		2013			2012			2011
	Current income tax expense (benefit)	$	7.8		$	6		$	(1.2	)
	Deferred tax benefit		(27.3	)		(34.1	)		(9.9	)
	Total income tax benefit, net	$	(19.5	)	$	(28.1	)	$	(11.1	)
Schedule of reconciliation of income taxes calculated at the Canadian enacted statutory rate to the provision for income taxes in the consolidated statements of operations	'
		Year ended December 31,
		2013			2012			2011
	Computed income taxes at Canadian statutory rate	$	(9.7	)	$	(36.2	)	$	(22.0	)
	Decreases resulting from:
	Operating countries with different income tax rates		(2.9	)		(8.5	)		(10.6	)
		$	(12.6	)	$	(44.7	)	$	(32.6	)
	Change in valuation allowance		12.1			20.2			21.7
			(0.5	)		(24.5	)		(10.9	)
	Dividend withholding tax and other cash taxes		3.7			5.9			0.4
	Foreign exchange		(9.9	)		1.5			(0.1	)
	Permanent differences		—			(6.5	)		(1.5	)
	Non-deductible acquisition costs		—			0.6			4.3
	Non-deductible interest expense		—			—			2.1
	Changes in tax rates		(4.1	)		1.8			—
	Federal grant		(18.9	)		—			(6.6	)
	Production tax credits		(4.5	)		—			—
	Changes in estimates of tax basis of equity method investments		(1.4	)		(5.1	)		2.2
	Goodwill impairment		13.6			—			—
	Other		2.5			(1.8	)		(1.0	)
			(19.0	)		(3.6	)		(0.2	)
		$	(19.5	)	$	(28.1	)	$	(11.1	)
Schedule of significant portions of the deferred tax assets and deferred tax liabilities	'
		2013			2012
	Deferred tax assets:
	Loss carryforwards	$	254.1		$	130.2
	Other accrued liabilities		0.4			10.9
	Finance and share issuance costs		6.7			8.3
	Disallowed interest carryforward		1.7			2.2
	Derivative contracts		27.8			3.5
	Other		8			6.1
	Total deferred tax assets		298.7			161.2
	Valuation allowance		(128.1	)		(116.0	)
			170.6			45.2
	Deferred tax liabilities:
	Intangible assets		(74.2	)		(113.3	)
	Property, plant and equipment		(194.8	)		(94.7	)
	Other long-term investments		(13.1	)		(1.2	)
	Total deferred tax liabilities		(282.1	)		(209.2	)
	Net deferred tax liability	$	(111.5	)	$	(164.0	)
Summary of the net deferred tax position	'
		2013			2012
	Long-term deferred tax liabilities	$	(111.5	)	$	(164.0	)
	Net deferred tax liability	$	(111.5	)	$	(164.0	)
Schedule of amounts of net operating loss carryforwards and their expiration years	'
	As of December 31, 2013, we had the following net operating loss carryforwards that are scheduled to expire in the following years:
	2027	$	50.3
	2028		101.6
	2029		82.5
	2030		25.8
	2031		57.3
	2032		85.6
	2033		299.3
		$	702.4

Equity_compensation_plans_Tabl

Equity compensation plans (Tables)	12 Months Ended
	Dec. 31, 2013
Equity compensation plans	'
Schedule of changes in LTIP notional shares	'
		Units			Grant Date
					Weighted-Average
					Fair Value per Unit
	Outstanding at December 31, 2010		600,981		$	10.28
	Granted		216,110			14.02
	Additional shares from dividends		36,204			11.04
	Forfeitures		(103,991	)		11.55
	Vested and redeemed		(263,523	)		9.4
	Outstanding at December 31, 2011		485,781			11.49
	Granted		233,752			14.67
	Additional shares from dividends		38,667			13.43
	Forfeitures		(28,932	)		13.63
	Vested and redeemed		(236,733	)		10.18
	Outstanding at December 31, 2012		492,535			13.9
	Granted		597,031			4.91
	Additional shares from dividends		64,576			8.74
	Forfeitures		(184,458	)		8.17
	Vested and redeemed		(202,696	)		13.48
	Outstanding at December 31, 2013		766,988		$	7.86
Schedule of assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'
		December 31, 2013			December 31, 2012
	Weighted average risk free rate of return		0.1 - 0.5	%		0.1 - 0.3	%
	Dividend yield		10.8	%		10.1	%
	Expected volatility—Atlantic Power		50.4	%		22.5	%
	Expected volatility—peer companies		11.4 - 56.4	%		11.9 - 97.1	%
	Weighted average remaining measurement period		1.82 years			1.39 years

Defined_benefit_plan_Tables

Defined benefit plan (Tables)	12 Months Ended
	Dec. 31, 2013
Defined benefit plan	'
Schedule of components of net annual periodic pension cost	'
		2013			2012
	Service cost benefits earned	$	0.9		$	0.8
	Interest cost on benefit obligation		0.7			0.6
	Expected return on plan assets		(0.8	)		(0.6	)
	Gain amortization		0.1			—
	Net period benefit cost	$	0.9		$	0.8
Schedule of comparison of the pension benefit obligation and related plan assets	'
		2013			2012
	Benefit obligation at January 1	$	(16.8	)	$	(12.7	)
	Service cost		(0.9	)		(0.8	)
	Interest cost		(0.7	)		(0.6	)
	Actuarial (gain) loss		1.4			(2.3	)
	Employee contributions		(0.1	)		(0.1	)
	Benefits paid		0.1			—
	Foreign currency translation adjustment		1			(0.3	)
	Benefit obligation at December 31		(16.0	)		(16.8	)
	Fair value of plan assets at January 1	$	12			10.5
	Actual return on plan assets		1.8			0.8
	Employer contributions		2.3			0.4
	Employee contributions		0.1			0.1
	Benefits paid		(0.1	)		—
	Foreign currency translation adjustment		(1.0	)		0.2
	Fair value of plan assets at December 31		15.1			12
	Funded status at December 31—excess of obligation over assets	$	(0.9	)	$	(4.8	)
Schedule of amount recognized in the balance sheet	'
		2013			2012
	Non-current liabilities	$	0.9		$	4.8
Schedule of amounts recognized in accumulated OCI that have not yet been recognized as components of net periodic benefit cost	'
		2013			2012
	Unrecognized loss	$	0.3		$	1.3
Schedule of significant components of pension plan	'
		2013			2012
	Projected benefit obligation	$	16		$	16.8
	Accumulated benefit obligation		12.4			13.1
	Fair value of plan assets		15.1			12
Schedule of significant assumptions used to calculate benefit obligations	'
		2013			2012
	Weighted-Average Assumptions
	Discount rate		5	%		4	%
	Rate of compensation increase		4	%		4	%
Schedule of significant assumptions used to calculate benefit expense	'
		2013			2012
	Weighted-Average Assumptions
	Discount rate		4.00%			4.00%
	Rate of return on plan assets		6.00%			5.50%
	Rate of compensation increase		3.0% - 4.0%			3.0% - 4.0%
Schedule of pension plan assets weighted average allocations in the common collective trust	'
		2013			2012
	Canadian equity		30	%		30	%
	U.S. equity		17	%		13	%
	International equity		15	%		14	%
	Canadian fixed income		38	%		40	%
	International fixed income		—			3	%
			100	%		100	%
Schedule of expected future benefit payments	'
	Our expected future benefit payments for each of the next five years and in the aggregate for the five years thereafter, are as follows in Cdn$:
		2013
	2014	$	0.1
	2015		0.2
	2016		0.3
	2017		0.3
	2018		0.4
	2019-2023		3.4

Basic_and_diluted_earnings_los1

Basic and diluted earnings (loss) per share (Tables)	12 Months Ended
	Dec. 31, 2013
Basic and diluted earnings (loss) per share	'
Schedule of diluted net income and potentially dilutive shares utilized in the per share calculation	'
		2013			2012			2011
	Numerator:
	Loss from continuing operations attributable to Atlantic Power Corporation	$	(26.8	)	$	(126.7	)	$	(72.7	)
	Income (loss) from discontinued operations, net of tax		(6.2	)		13.9			34.3
	Net loss attributable to Atlantic Power Corporation	$	(33.0	)	$	(112.8	)	$	(38.4	)
	Denominator:
	Weighted average basic shares outstanding		119.9			116.4			77.5
	Dilutive potential shares:
	Convertible debentures		27.7			17.4			14
	LTIP notional units		0.7			0.5			0.4
	Potentially dilutive shares		148.3			134.3			91.9
	Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.23	)	$	(1.09	)	$	(0.94	)
	Diluted earnings (loss) per share from discontinued operations		(0.05	)		0.12			0.44
	Diluted loss per share attributable to Atlantic Power Corporation	$	(0.28	)	$	(0.97	)	$	(0.50	)

Assets_held_for_sale_Tables

Assets held for sale (Tables) (Path 15)	12 Months Ended
	Dec. 31, 2013
Path 15	'
Held for Sale Business	'
Summary of income (loss) from discontinued operations	'
		December 31,
		2013			2012		2011
	Revenue	$	71.6		$	216.7	$	191
	Income (loss) from discontinued operations		(5.4	)		15.7		37.1
	Income tax expense		0.8			1.8		2.8
	Income (loss) from discontinued operations, net of tax	$	(6.2	)	$	13.9	$	34.3
Schedule of assets and liabilities held for sale	'
		December 31,
		2012
	Current assets:
	Cash and cash equivalents	$	6.5
	Restricted cash		12.6
	Accounts receivable		21.9
	Other current assets		6.3
			47.3
	Non-current assets:
	Property, plant, and equipment		111.9
	Transmission system rights		172.4
	Goodwill		8.9
	Other assets		10.9
	Assets held for sale	$	351.4
	Current liabilities:
	Accounts payable and other accrued liabilities	$	16.5
	Current portion of long-term debt		14.3
	Current portion of derivative instrument asset		20
	Other liabilities		0.5
			51.3
	Long term liabilities
	Long-term debt		137.7
	Liabilities held for sale	$	189

Segment_and_geographic_informa1

Segment and geographic information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment and geographic information	'
Schedule of a reconciliation of project income to Project Adjusted EBITDA	'
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Year ended December 31, 2013
	Project revenues	$	299.1		$	182.3		$	70.8		$	(0.5	)	$	551.7
	Segment assets		1,395.20			1,001.50			853.9			144.4			3,395.00
	Goodwill		107.8			188.5			—			—			296.3
	Capital expenditures		13.8			1.1			11.1			0.2			26.2
	Project Adjusted EBITDA	$	150.7		$	78.8		$	59.6		$	(18.6	)	$	270.5
	Change in fair value of derivative instruments		(24.4	)		—			(25.9	)		—			(50.3	)
	Depreciation and amortization		93.7			68.3			47.3			0.5			209.8
	Interest, net		20.7			0.4			19.5			(2.1	)		38.5
	Other project (income) expense		34.9			(26.3	)		0.1			(0.5	)		8.2
	Project income (loss)		25.8			36.4			18.6			(16.5	)		64.3
	Administration		—			—			—			35.2			35.2
	Interest, net		—			—			—			104.1			104.1
	Foreign exchange gain		—			—			—			(27.4	)		(27.4	)
	Other income, net		—			—			—			(10.5	)		(10.5	)
	Income (loss) from continuing operations before income taxes		25.8			36.4			18.6			(117.9	)		(37.1	)
	Income tax benefit		—			—			—			(19.5	)		(19.5	)
	Net income (loss) from continuing operations		25.8			36.4			18.6			(98.4	)		(17.6	)
	Income (loss) from discontinued operations		(1.1	)		1.3			—			(6.4	)		(6.2	)
	Net income (loss)	$	24.7		$	37.7		$	18.6		$	(104.8	)	$	(23.8	)
		East			West			Wind			Un-allocated			Consolidated
											Corporate
	Year ended December 31, 2012
	Project revenues	$	267.5		$	169.6		$	1.9		$	1.4		$	440.4
	Segment assets		1,600.20			1,305.30			956.3			140.9			4,002.70
	Goodwill		138.6			192.6			—			3.5			334.7
	Capital expenditures		25.5			0.2			441.6			0.8			468.1
	Project Adjusted EBITDA	$	145.7		$	82.1		$	10.9		$	(11.1	)	$	227.6
	Change in fair value of derivative instruments		56.6			—			—			—			56.6
	Depreciation and amortization		87.5			71.4			5.9			0.1			164.9
	Interest, net		18.5			0.4			5.1			—			24
	Other project expense		1.2			3			7.3			—			11.5
	Project (loss) income		(18.1	)		7.3			(7.4	)		(11.2	)		(29.4	)
	Administration		—			—			—			28.3			28.3
	Interest, net		—			—			—			89.8			89.8
	Foreign exchange loss		—			—			—			0.5			0.5
	Other income, net		—			—			—			(5.7	)		(5.7	)
	Income (loss) from continuing operations before income taxes		(18.1	)		7.3			(7.4	)		(124.1	)		(142.3	)
	Income tax benefit		—			—			—			(28.1	)		(28.1	)
	Net income (loss) from continuing operations		(18.1	)		7.3			(7.4	)		(96.0	)		(114.2	)
	Income (loss) from discontinued operations		13.6			2.9			—			(2.6	)		13.9
	Net income (loss)	$	(4.5	)	$	10.2		$	(7.4	)	$	(98.6	)	$	(100.3	)
		East			West			Wind			Un-allocated Corporate			Consolidated
	Year ended December 31, 2011
	Project revenues	$	66		$	26.6		$	—		$	1.3		$	93.9
	Segment assets		1,683.90			1,392.10			48.6			123.8			3,248.40
	Goodwill		138.6			201.5			—			3.5			343.6
	Capital expenditures		115			0.1			—			—			115.1
	Project Adjusted EBITDA	$	66.8		$	16.4		$	4.3		$	(0.7	)	$	86.8
	Change in fair value of derivative instruments		17.5			—			—			(0.3	)		17.2
	Depreciation and amortization		37.3			15.2			3			—			55.5
	Interest, net		11.5			0.8			2.9			—			15.2
	Other project (income) expense		2.6			(0.3	)		—			0.2			2.5
	Project (loss) income		(2.1	)		0.7			(1.6	)		(0.6	)		(3.6	)
	Administration		—			—			—			37.7			37.7
	Interest, net		—			—			—			26			26
	Foreign exchange loss		—			—			—			13.8			13.8
	Other income, net		—			—			—			(0.1	)		(0.1	)
	Income (loss) from continuing operations before income taxes		(2.1	)		0.7			(1.6	)		(78.0	)		(81.0	)
	Income tax benefit		—			—			—			(11.1	)		(11.1	)
	Net income (loss) from continuing operations		(2.1	)		0.7			(1.6	)		(66.9	)		(69.9	)
Income (loss) from discontinued operations		31.8			4.4			—			(1.9	)		34.3
Net income (loss)	$	29.7		$	5.1		$	(1.6	)	$	(68.8	)	$	(35.6	)
	Northeast			Southeast			Northwest			Southwest			Un-allocated			Consolidated
													Corporate
Year ended December 31, 2013
Project revenues	$	227.2		$	22		$	88.6		$	214.4		$	(0.5	)	$	551.7
Segment assets		1,136.10			170.7			1,050.80			893			144.4			3,395.00
Goodwill		104.5			—			138.3			53.5			—			296.3
Capital expenditures		4.3			9.5			4.7			7.5			0.2			26.2
Project Adjusted EBITDA	$	133.1		$	11.3		$	67.2		$	77.5		$	(18.6	)		270.5
Change in fair value of derivative instruments		(19.4	)		(5.0	)		(25.9	)		—			—			(50.3	)
Depreciation and amortization		79.4			10.7			60.3			58.9			0.5			209.8
Interest, net		17			3.6			18.9			1.1			(2.1	)		38.5
Other project (income) expense		34.5			0.1			0.1			(26.0	)		(0.5	)		8.2
Project income (loss)		21.6			1.9			13.8			43.5			(16.5	)		64.3
Administration		—			—			—			—			35.2			35.2
Interest, net		—			—			—			—			104.1			104.1
Foreign exchange gain		—			—			—			—			(27.4	)		(27.4	)
Other income, net		—			—			—			—			(10.5	)		(10.5	)
Income (loss) from continuing operations before income taxes		21.6			1.9			13.8			43.5			(117.9	)		(37.1	)
Income tax benefit		—			—			—			—			(19.5	)		(19.5	)
Net income (loss) from continuing operations		21.6			1.9			13.8			43.5			(98.4	)		(17.6	)
Income (loss) from discontinued operations		—			(1.1	)		—			1.3			(6.4	)		(6.2	)
Net income (loss)	$	21.6		$	0.8		$	13.8		$	44.8		$	(104.8	)	$	(23.8	)
Schedule of revenue and property, plant and equipment by country	'
		Revenue									Property, Plant &
											Equipment, net
		2013			2012			2011			2013			2012
	United States	$	343.4		$	227.2		$	58.1		$	1,330.50		$	1,504.80
	Canada		208.3			213.2			35.8			482.9			550.7
	Total	$	551.7		$	440.4		$	93.9		$	1,813.40		$	2,055.50

Commitments_and_contingencies_

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and contingencies.	'
Schedule of future minimum lease commitments under operating leases	'
	Future minimum lease commitments under operating leases for the years ending after December 31, 2013, are as follows:
	2014	$	1.6
	2015		1.8
	2016		1.7
	2017		1.6
	2018		1.5
	Thereafter		12.9
		$	21.1
Schedule of estimated commitments under long-term service agreements	'
	As of December 31, 2013, our commitments under such outstanding agreements are estimated as follows:
	2014	$	3.5
	2015		5
	2016		5
	2017		5
	2018		5
	Thereafter		24.4
		$	47.9
Schedule of estimated commitments under fuel supply and transportation agreements	'
	As of December 31, 2013, our commitments under such outstanding agreements are estimated as follows:
	2014	$	83
	2015		80
	2016		73
	2017		23.4
	2018		23.6
	Thereafter		70.4
		$	353.4

Unaudited_selected_quarterly_f1

Unaudited selected quarterly financial data (Tables)	12 Months Ended
	Dec. 31, 2013
Unaudited selected quarterly financial data	'
Schedule of unaudited selected quarterly financial data	'
		Quarter Ended
		2013
		December 31,			September 30,			June 30,			March 31,			Total
	Project revenue	$	130.7		$	141.8		$	139.1		$	140.1		$	551.7
	Project income		7.2			4.8			20.8			31.5			64.3
	Income (loss) from continuing operations		8.2			(40.2	)		7.2			7.2			(17.6	)
	Income (loss) from discontinued operations		(0.2	)		(0.4	)		(6.0	)		0.4			(6.2	)
	Net income (loss) attributable to Atlantic Power Corporation		4.9			(41.3	)		(3.0	)		6.4			(33.0	)
	Income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	0.02		$	0.05		$	(0.23	)
	Loss per share from discontinued operations		—			—			(0.05	)		—			(0.05	)
	Income (loss) per share attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	(0.03	)	$	0.05		$	(0.28	)
	Weighted average number of common shares outstanding-basic		120.1			120			119.9			119.5			119.9
	Diluted income (loss) per share from continuing operations attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	0.02		$	0.05		$	(0.23	)
	Diluted loss per share from discontinued operations		—			—			(0.05	)		—			(0.05	)
	Diluted income (loss) per share attributable to Atlantic Power Corporation	$	0.04		$	(0.34	)	$	(0.03	)	$	0.05		$	(0.28	)
	Weighted average number of common shares outstanding-diluted(1)		120.1			120			119.9			119.5			119.9
	-1
	The calculation excludes potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units because their impact would be anti-dilutive.
		Quarter Ended
		2012
		December 31,			September 30,			June 30,			March 31,			Total
	Project revenue	$	114		$	106.3		$	101.4		$	118.7		$	440.4
	Project (loss) income		(5.8	)		19.7			(6.9	)		(36.4	)		(29.4	)
	Loss from continuing operations		(19.7	)		(23.5	)		(20.8	)		(50.2	)		(114.2	)
	(Loss) income from discontinued operations		(34.8	)		19			18.7			11			13.9
	Net loss attributable to Atlantic Power Corporation		(58.0	)		(7.4	)		(5.1	)		(42.3	)		(112.8	)
	Loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.20	)	$	(0.22	)	$	(0.20	)	$	(0.47	)	$	(1.09	)
	Earnings (loss) per share from discontinued operations		(0.30	)		0.16			0.16			0.1			0.12
	Loss per share attributable to Atlantic Power Corporation	$	(0.50	)	$	(0.06	)	$	(0.04	)	$	(0.37	)	$	(0.97	)
	Weighted average number of common shares outstanding-basic		119.4			119			113.7			113.6			116.4
	Diluted loss per share from continuing operations attributable to Atlantic Power Corporation	$	(0.20	)	$	(0.22	)	$	(0.20	)	$	(0.47	)	$	(1.09	)
	Diluted (loss) earnings per share from discontinued operations		(0.30	)		0.16			0.16			0.1			0.12
	Diluted loss per share attributable to Atlantic Power Corporation	$	(0.50	)	$	(0.06	)	$	(0.04	)	$	(0.37	)	$	(0.97	)
	Weighted average number of common shares outstanding-diluted(1)		119.4			119			113.7			113.6			116.4
	-1
	The calculation excludes potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units because their impact would be anti-dilutive.

Consolidating_financial_inform1

Consolidating financial information (Tables)	12 Months Ended
	Dec. 31, 2013
Consolidating financial information	'
Schedule of consolidating balance sheet	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING BALANCE SHEET
	December 31, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
		Subsidiaries												Balance
	Assets
	Current assets:
	Cash and cash equivalents	$	151		$	—		$	7.6		$	—		$	158.6
	Restricted cash		114.2			—			—			—			114.2
	Accounts receivable		181.2			17.6			4.3			(138.8	)		64.3
	Prepayments, supplies, and other		33.3			1.3			1.7			—			36.3
	Total current assets		479.7			18.9			13.6			(138.8	)		373.4
	Property, plant, and equipment, net		1,642.60			172.1			—			(1.3	)		1,813.40
	Equity investments in unconsolidated affiliates		3,655.00			—			943.8			(4,204.5	)		394.3
	Other intangible assets, net		304.7			146.8			—			—			451.5
	Goodwill		238.1			58.2			—						296.3
	Other assets		476.7			—			435.1			(845.7	)		66.1
	Total assets	$	6,796.80		$	396		$	1,392.50		$	(5,190.3	)	$	3,395.00
	Liabilities
	Current liabilities:
	Accounts payable and accrued liabilities	$	141.9		$	6.1		$	81.3		$	(138.8	)	$	90.5
	Current portion of long-term debt		26.2			190			—			—			216.2
	Current portion convertible debentures		—			—			42.1			—			42.1
	Dividends payable		6.8			—			—			—			6.8
	Other current liabilities		30			—			3.8			—			33.8
	Total current liabilities		204.9			196.1			127.2			(138.8	)		389.4
	Long-term debt		794.8			—			460			—			1,254.80
	Convertible debentures		—			—			363.1			—			363.1
	Other non-current liabilities		1,128.30			8.6			0.5			(845.7	)		291.7
	Equity
	Common Stock		4,226.20			191.3			1,286.10			(4,417.5	)		1,286.10
	Preferred shares issued by a subsidiary company		221.3			—			—			—			221.3
	Accumulated other comprehensive income		(22.4	)		—			—						(22.4	)
	Retained (deficit) earnings		(22.7	)		—			(844.4	)		211.7			(655.4	)
	Total Atlantic Power Corporation shareholders' equity		4,402.40			191.3			441.7			(4,205.8	)		829.6
	Noncontrolling interests		266.4			—			—			—			266.4
	Total equity		4,668.80			191.3			441.7			(4,205.8	)		1,096.00
	Total liabilities and equity	$	6,796.80		$	396		$	1,392.50		$	(5,190.3	)	$	3,395.00
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING BALANCE SHEET
	December 31, 2012
	(in millions of U.S. dollars)
		Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
		Subsidiaries												Balance
	Assets
	Current assets:
	Cash and cash equivalents	$	43.2		$	—		$	17		$	—		$	60.2
	Restricted cash		28.6			—			—			—			28.6
	Accounts receivable		138.8			35.8			0.9			(117.0	)		58.5
	Prepayments, supplies, and other		53.4			1.3			9.3			(1.0	)		63
	Asset held for sale		351.4			—			—			—			351.4
	Total current assets		615.4			37.1			27.2			(118.0	)		561.7
	Property, plant, and equipment, net		1,883.60			173.1			—			(1.2	)		2,055.50
	Equity investments in unconsolidated affiliates		5,109.30			—			1,012.00			(5,692.6	)		428.7
	Other intangible assets, net		367.1			157.8			—			—			524.9
	Goodwill		276.5			58.2			—			—			334.7
	Other assets		499.7			—			440.1			(842.6	)		97.2
	Total assets	$	8,751.60		$	426.2		$	1,479.30		$	(6,654.4	)	$	4,002.70
	Liabilities
	Current liabilities:
	Accounts payable and accrued liabilities	$	169.8		$	13.7		$	44		$	(117.0	)	$	110.5
	Revolving credit facility		47			—			20			—			67
Current portion of long-term debt		121.2			—			—			—			121.2
Liabilities held for sale		189			—			—			—			189
Other current liabilities		37.3			—			11.5			(1.0	)		47.8
Total current liabilities		564.3			13.7			75.5			(118.0	)		535.5
Long-term debt		809.1			190			460			—			1,459.10
Convertible debentures		—			—			424.2			—			424.2
Other non-current liabilities		1,230.80			8.3			1			(842.6	)		397.5
Equity
Common Stock		5,103.80			214.2			1,285.50			(5,318.0	)		1,285.50
Preferred shares issued by a subsidiary company		221.3			—			—			—			221.3
Accumulated other comprehensive income		9.4			—			—			—			9.4
Retained earnings (deficit)		577.5			—			(766.9	)		(375.8	)		(565.2	)
Total Atlantic Power Corporation shareholders' equity		5,912.00			214.2			518.6			(5,693.8	)		951
Noncontrolling interests		235.4			—			—			—			235.4
Total equity		6,147.40			214.2			518.6			(5,693.8	)		1,186.40
Total liabilities and equity	$	8,751.60		$	426.2		$	1,479.30		$	(6,654.4	)	$	4,002.70
Consolidating statement of operations	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	December 31, 2013
	(in millions of U.S. dollars, except per share amounts)
		Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
		Subsidiaries												Balance
	Project revenue:
	Energy sales	$	268.4		$	35.8		$	—		$	—		$	304.2
	Energy capacity revenue		168.8			—			—			—			168.8
	Other		79.2			—			—			(0.5	)		78.7
			516.4			35.8			—			(0.5	)		551.7
	Project expenses:
	Fuel		198.7			—			—			—			198.7
	Project operations and maintenance		148.2			3.8			0.9			(0.5	)		152.4
	Project development expenses		7.2			—			—			—			7.2
	Depreciation and amortization		151.7			15.4			—			—			167.1
			505.8			19.2			0.9			(0.5	)		525.4
	Project other income (expense):
	Change in fair value of derivative instruments		49.5			—			—			—			49.5
	Equity in earnings of unconsolidated affiliates		26.9			—			—			—			26.9
	Gain on sale of equity investments		30.4			—			—			—			30.4
	Interest expense, net		(23.3	)		(11.1	)		—			—			(34.4	)
	Other income, net		(34.7	)		—			0.3			—			(34.4	)
			48.8			(11.1	)		0.3			—			38
	Project income (loss)		59.4			5.5			(0.6	)		—			64.3
	Administrative and other expenses (income):
	Administration expense		21.1						14.1			—			35.2
	Interest, net		75.8						28.3			—			104.1
	Foreign exchange loss		(9.4	)					(18.0	)		—			(27.4	)
	Other income		(5.8	)					(4.7	)		—			(10.5	)
			81.7						19.7			—			101.4
	Loss from continuing operations before income taxes		(22.3	)		5.5			(20.3	)		—			(37.1	)
	Income tax benefit		(19.5	)		—						—			(19.5	)
	Net loss from continuing operations		(2.8	)		5.5			(20.3	)		—			(17.6	)
	Net loss from discontinued operations, net of tax		(6.2	)		—			—			—			(6.2	)
	Net loss		(9.0	)		5.5			(20.3	)		—			(23.8	)
	Net loss attributable to noncontrolling interests		(3.4	)		—			—			—			(3.4	)
	Net income attributable to preferred share dividends of a subsidiary company		12.6			—			—			—			12.6
	Net loss attributable to Atlantic Power Corporation	$	(18.2	)	$	5.5		$	(20.3	)	$	—		$	(33.0	)
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	December 31, 2012
	(in millions of U.S. dollars, except per share amounts)
		Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
		Subsidiaries												Balance
	Project revenue:
	Energy sales	$	182.8		$	34.2		$	—		$	—		$	217
	Energy capacity revenue		154.9			—			—			—			154.9
	Other		69.1			—			—			(0.6	)		68.5
			406.8			34.2			—			(0.6	)		440.4
	Project expenses:
	Fuel		169.1			—			—			—			169.1
	Project operations and maintenance		117.3			6.1			(0.2	)		(0.4	)		122.8
	Depreciation and amortization		102.7			15.3			—			—			118
			389.1			21.4			(0.2	)		(0.4	)		409.9
	Project other income (expense):
	Change in fair value of derivative instruments		(59.3	)		—			—			—			(59.3	)
	Equity in earnings of unconsolidated affiliates		15.8			—			—			—			15.8
	Interest expense, net		(5.2	)		(11.2	)		—			—			(16.4	)
			(48.7	)		(11.2	)		—			—			(59.9	)
	Project income (loss)		(31.0	)		1.6			0.2			(0.2	)		(29.4	)
	Administrative and other expenses (income):
	Administration expense		17.6			—			10.7			—			28.3
Interest, net		79.6			—			10			0.2			89.8
Foreign exchange loss		1.1			—			(0.6	)		—			0.5
Other income		(6.0	)		—			0.3			—			(5.7	)
		92.3			—			20.4			0.2			112.9
(Loss) income from continuing operations before income taxes		(123.3	)		1.6			(20.2	)		(0.4	)		(142.3	)
Income tax benefit		(28.1	)		—			—			—			(28.1	)
Net (loss) income from continuing operations		(95.2	)		1.6			(20.2	)		(0.4	)		(114.2	)
Net income from discontinued operations, net of tax		13.9			—			—			—			13.9
Net (loss) income		(81.3	)		1.6			(20.2	)		(0.4	)		(100.3	)
Net loss attributable to noncontrolling interests		(0.6	)		—									(0.6	)
Net income attributable to preferred share dividends of a subsidiary company		13.1			—			—			—			13.1
Net (loss) income attributable to Atlantic Power Corporation	$	(93.8	)	$	1.6		$	(20.2	)	$	(0.4	)	$	(112.8	)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
December 31, 2011
(in millions of U.S. dollars, except per share amounts)
	Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
	Subsidiaries												Balance
Project revenue:
Energy sales	$	34.6		$	9		$	—		$	—		$	43.6
Energy capacity revenue		34			—			—			—			34
Other		16.7			—			—			(0.4	)		16.3
		85.3			9			—			(0.4	)		93.9
Project expenses:
Fuel		37.5			—			—			—			37.5
Project operations and maintenance		19.4			0.9			0.9			(0.3	)		20.9
Depreciation and amortization		21			2.6			—			—			23.6
		77.9			3.5			0.9			(0.3	)		82
Project other income (expense):
Change in fair value of derivative instruments		(14.6	)		—			—			—			(14.6	)
Equity in earnings of unconsolidated affiliates		6			—			—			0.4			6.4
Interest expense, net		(3.9	)		(1.9	)		0.1			(1.6	)		(7.3	)
		(12.5	)		(1.9	)		0.1			(1.2	)		(15.5	)
Project income (loss)		(5.1	)		3.6			(0.8	)		(1.3	)		(3.6	)
Administrative and other expenses (income):
Administration expense		12.2			—			25.5			—			37.7
Interest, net		67.7			—			(41.7	)		—			26
Foreign exchange loss		4			—			9.8			—			13.8
Other Income, net		(0.1	)		—			—			—			(0.1	)
		83.8			—			(6.4	)		—			77.4
(Loss) income from continuing operations before income taxes		(88.9	)		3.6			5.6			(1.3	)		(81.0	)
Income tax (benefit) expense		(11.3	)		—			0.2			—			(11.1	)
Net (loss) income from continuing operations		(77.6	)		3.6			5.4			(1.3	)		(69.9	)
Net income from discontinued operations, net of tax		34.3			—			—			—			34.3
Net (loss) income		(43.3	)		3.6			5.4			(1.3	)		(35.6	)
Net loss attributable to noncontrolling interests		(0.5	)		—			—			—			(0.5	)
Net income attributable to preferred share dividends of a subsidiary company		3.3			—			—			—			3.3
Net (loss) income attributable to Atlantic Power Corporation	$	(46.1	)	$	3.6		$	5.4		$	(1.3	)	$	(38.4	)
Consolidating statement of comprehensive income	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME
	December 31, 2013, 2012, and 2011
	(in millions of U.S. dollars)
		Year ended December 31, 2013
		Guarantor			Curtis			APC			Eliminations			Consolidated
		Subsidiaries			Palmer									Balance
	Net loss	$	(9.0	)	$	(14.2	)	$	(0.6	)	$	—		$	(23.8	)
	Other comprehensive income:
	Unrealized income on hedging activities		0.7			—			—			—			0.7
	Net amount reclassified to earnings		0.9			—			—			—			0.9
	Net unrealized gain on derivatives		1.6			—			—			—			1.6
															—
	Defined benefit plan, net of tax		1.4			—			—			—			1.4
	Foreign currency translation adjustments		(34.8	)		—			—			—			(34.8	)
	Other comprehensive loss, net of tax		(31.8	)		—			—			—			(31.8	)
	Comprehensive loss		(40.8	)		(14.2	)		(0.6	)		—			(55.6	)
	Less: Comprehensive income attributable to noncontrolling interests		9.2			—			—			—			9.2
	Comprehensive loss attributable to Atlantic Power Corporation	$	(50.0	)	$	(14.2	)	$	(0.6	)	$	—		$	(64.8	)
		Year ended December 31, 2012
		Guarantor			Curtis			APC			Eliminations			Consolidated
		Subsidiaries			Palmer									Balance
	Net (loss) income	$	(81.3	)	$	1.6		$	(20.2	)	$	(0.4	)	$	(100.3	)
	Other comprehensive income (loss):
	Unrealized loss on hedging activities		(0.9	)		—			—			—			(0.9	)
	Net amount reclassified to earnings		0.9			—			—			—			0.9
	Net unrealized losses on derivatives		—			—			—			—			—
															—
	Defined benefit plan, net of tax		(1.3	)		—			—			—			(1.3	)
	Foreign currency translation adjustments		15.9			—			—			—			15.9
	Other comprehensive income, net of tax		14.6			—			—			—			14.6
	Comprehensive (loss) income		(66.7	)		1.6			(20.2	)		(0.4	)		(85.7	)
	Less: Comprehensive income attributable to noncontrolling interests		12.5			—			—			—			12.5
	Comprehensive (loss) income attributable to Atlantic Power Corporation	$	(79.2	)	$	1.6		$	(20.2	)	$	(0.4	)	$	(98.2	)
		Year ended December 31, 2011
		Guarantor			Curtis			APC			Eliminations			Consolidated
		Subsidiaries			Palmer									Balance
	Net (loss) income	$	(43.3	)	$	3.6		$	5.4		$	(1.3	)	$	(35.6	)
	Other comprehensive income (loss):
	Unrealized loss on hedging activities		(2.6	)		—			—			—			(2.6	)
	Net amount reclassified to earnings		1			—			—			—			1
	Net unrealized losses on derivatives		(1.6	)		—			—			—			(1.6	)
															—
	Defined benefit plan, net of tax		(0.5	)		—			—			—			(0.5	)
	Foreign currency translation adjustments		(3.3	)		—			—			—			(3.3	)
	Other comprehensive loss, net of tax		(5.4	)		—			—			—			(5.4	)
	Comprehensive (loss) income		(48.7	)		3.6			5.4			(1.3	)		(41.0	)
	Less: Comprehensive income attributable to noncontrolling interests		2.8			—			—			—			2.8
	Comprehensive (loss) income attributable to Atlantic Power Corporation	$	(51.5	)	$	3.6		$	5.4		$	(1.3	)	$	(43.8	)
Consolidating statement of cash flows	'
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	December 31, 2013
	(in millions of U.S. dollars)
		Guarantor			Curtis			APC			Eliminations			Consolidated
		Subsidiaries			Palmer									Balance
	Cash flows from operating activities:
	Net cash provided by operating activities:	$	61.7		$	3		$	87.7		$	—		$	152.4
	Cash flows provided by (used in) investing activities:
	Proceeds from treasury grant		103.2			—			—			—			103.2
	Proceeds from sale of assets		182.6			—			—			—			182.6
	Cash (paid) received for equity investments		11			—			(11.0	)		—			—
	Change in restricted cash		(93.7	)		—			—			—			(93.7	)
	Biomass development costs		(0.2	)		—			—			—			(0.2	)
	Construction in progress		(38.3	)		—			—			—			(38.3	)
	Purchase of property, plant and equipment		(3.5	)		(3.0	)		—			—			(6.5	)
	Net cash provided by (used in) investing activities		161.1			(3.0	)		(11.0	)		—			147.1
	Cash flows (used in) provided by financing activities:
	Proceeds from issuance of convertible debentures		—			—			—			—			—
	Offering costs related to tax equity		(1.0	)		—			—			—			(1.0	)
	Repayment of project-leve debt		(118.8	)		—			—			—			(118.8	)
	Proceeds from project-level debt		20.8			—			—			—			20.8
	Payments for revolving credit facilities		(47.0	)		—			(20.0	)		—			(67.0	)
	Equity investment from noncontrolling interest		42.7			—			1.9			—			44.6
	Deferred financing costs		—			—			(2.8	)		—			(2.8	)
	Dividends paid		(18.3	)		—			(65.1	)		—			(83.4	)
	Net cash used in financing activities		(121.6	)		—			(86.0	)		—			(207.6	)
	Net increase (decrease) in cash and cash equivalents		101.2			—			(9.3	)		—			91.9
	Cash and cash equivalents at beginning of period		49.8			—			16.9			—			66.7
	Cash and cash equivalents at end of period	$	151		$	—		$	7.6		$	—		$	158.6
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	December 31, 2012
	(in millions of U.S. dollars)
		Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
		Subsidiaries												Balance
	Cash flows from operating activities:
	Net cash (used in) provided by operating activities:	$	(9.9	)	$	1.1		$	175.9		$	—		$	167.1
	Cash flows (used in) provided by investing activities:
	Cash paid for acquisitions and investments, net of cash acquired		206.5			—			(287.0	)		—			(80.5	)
	Proceeds from sale of assets and equity investments, net		27.9			—			—			—			27.9
	Construction in progress		(456.2	)		—			—			—			(456.2	)
	Change in restricted cash		(11.6	)		—			—			—			(11.6	)
	Biomass development costs		(0.5	)		—			—			—			(0.5	)
	Purchase of property, plant and equipment		(1.8	)		(1.1	)		—			—			(2.9	)
	Net cash used in investing activities		(235.7	)		(1.1	)		(287.0	)		—			(523.8	)
	Cash flows (used in) provided by financing activities:
	Proceeds from issuance of convertible debentures		—			—			230.6			—			230.6
	Proceeds from issuance of equity, net of offering costs		(1.4	)		—			67.7			—			66.3
	Repayment of project-level debt		(284.8	)		—			—			—			(284.8	)
	Deferred financing costs		(19.7	)		—			(11.5	)		—			(31.2	)
	Proceeds from project-level debt		291.9			—			—			—			291.9
	Payments for revolving credit facilities		(30.8	)		—			(30.0	)		—			(60.8	)
	Proceeds from revolving credit facility borrowings		69.8			—			—			—			69.8
	Equity contribution from noncontrolling interest		225			—			—			—			225
	Dividends paid		(13.1	)		—			(131.0	)		—			(144.1	)
	Net cash provided by financing activities		236.9			—			125.8			—			362.7
	Net (decrease) increase in cash and cash equivalents		(8.7	)		—			14.7			—			6
	Less cash at discontinued operations		(6.5	)		—			—			—			(6.5	)
	Cash and cash equivalents at beginning of period		58.4			—			2.3			—			60.7
	Cash and cash equivalents at end of period	$	43.2		$	—		$	17		$	—		$	60.2
	ATLANTIC POWER CORPORATION
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
December 31, 2011
(in millions of U.S. dollars)
	Guarantor			Curtis Palmer			APC			Eliminations			Consolidated
	Subsidiaries												Balance
Cash flows from operating activities:
Net cash provided by operating activities:	$	21		$	—		$	34.9		$	—		$	55.9
Cash flows provided by (used in) investing activities:
Cash paid for acquisitions and investments, net of cash acquired		12.1			—			(603.7	)		—			(591.6	)
Short-term loan to Idaho Wind		21.5			—			1.3			—			22.8
Proceeds from sale of assets and equity investments, net		8.5			—			—			—			8.5
Change in restricted cash		(5.7	)		—			—			—			(5.7	)
Biomass development costs		(0.9	)		—			—			—			(0.9	)
Construction in progress		(113.1	)		—			—			—			(113.1	)
Purchase of property, plant and equipment		(2.0	)		—			—			—			(2.0	)
Net cash used in investing activities		(79.6	)		—			(602.4	)		—			(682.0	)
Cash flows (used in) provided by financing activities:
Proceeds from issuance of long-term debt		—			—			460			—			460
Proceeds from issuance of equity, net of offering costs		—			—			155.4			—			155.4
Repayment of project-level debt		(21.5	)		—			—			—			(21.5	)
Deferred financing costs		—			—			(26.4	)		—			(26.4	)
Proceeds from project-level debt		100.8			—			—			—			100.8
Proceeds from revolving credit facility borrowings		8			—			50			—			58
Dividends paid		(3.2	)		—			(81.8	)		—			(85.0	)
Net cash provided by financing activities		84.1			—			557.2			—			641.3
Net increase (decrease) in cash and cash equivalents		25.5			—			(10.3	)		—			15.2
Cash and cash equivalents at beginning of period		33			—			12.5			—			45.5
Cash and cash equivalents at end of period	$	58.5		$	—		$	2.2		$	—		$	60.7

Nature_of_business_Details

Nature of business (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 07, 2012
	MW	Delta-Person
	state
	province
	project
Basis of presentation and summary of significant accounting policies	'	'
Percentage of ownership interest	'	40.00%
Gross generating capacity of project (in MW)	2,948	'
Ownership interest in operational power generation projects (in MW)	2,026	'
Number of operational power generation projects	28	'
Number of states in which power generation projects operate	11	'
Number of provinces in which power generation projects operate	2	'
Number of projects Which are wholly owned subsidiaries	22	'

Summary_of_significant_account3

Summary of significant accounting policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
Deferred financing costs	'	'	'
Net carrying amount of deferred financing cost	$41.70	$47.20	'
Amortization expense	8	4.4	1.3
Project development costs and capitalized interest	'	'	'
Capitalized interest	$1.90	$17	$3
Derivative financial instruments	'	'	'
Number of interest rate swaps designated as cash flow hedges	1	'	'
Minimum	'	'	'
Deferred financing costs	'	'	'
Amortization period	'5 years	'	'
Investments accounted for by the equity method	'	'	'
Percentage of investments in partnerships and limited liability companies in which the entity is having the ability to exercise significant influence over operating and financial policies	5.00%	'	'
Maximum	'	'	'
Deferred financing costs	'	'	'
Amortization period	'28 years	'	'
Property, plant and equipment	'	'	'
Estimated useful lives	'45 years	'	'
Investments accounted for by the equity method	'	'	'
Percentage of investments in partnerships and limited liability companies in which the entity is having the ability to exercise significant influence over operating and financial policies	50.00%	'	'
Impairment of long-lived assets, non-amortizing intangible assets and equity method investments	'	'	'
Maximum percentage of ownership in entities in which consolidation is not required	50.00%	'	'

Summary_of_significant_account4

Summary of significant accounting policies (Details 2) (Long-term incentive plan)	12 Months Ended
	Dec. 31, 2013
Equity compensation plans	'
Vesting period	'3 years
Portion of vested notional units expected to be redeemed in cash	33.00%
Portion of vested notional units expected to be redeemed in shares	67.00%
Minimum	'
Equity compensation plans	'
Vesting percentage	0.00%
Maximum	'
Equity compensation plans	'
Vesting percentage	150.00%
Officers	'
Equity compensation plans	'
Vesting period	'3 years
Non-officers	'
Equity compensation plans	'
Vesting period	'3 years
Senior officers	'
Equity compensation plans	'
Vesting period	'3 years
Vesting percentage	33.00%

Summary_of_significant_account5

Summary of significant accounting policies (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in accumulated other comprehensive income (loss) by component	'	'	'
Balance at beginning of period	$9.40	'	'
Other comprehensive income (loss):	'	'	'
Foreign currency translation adjustments	-34.8	15.9	-3.3
Tax benefit (expense)	-19.5	-28.1	-11.1
Total Other comprehensive income (loss)	-31.8	14.6	-5.4
Balance at end of period	-22.4	9.4	'
Foreign currency translation	'	'	'
Changes in accumulated other comprehensive income (loss) by component	'	'	'
Balance at beginning of period	12.6	-3.3	'
Other comprehensive income (loss):	'	'	'
Foreign currency translation adjustments	-34.8	15.9	-3.3
Balance at end of period	-22.2	12.6	-3.3
Cash flow hedges	'	'	'
Changes in accumulated other comprehensive income (loss) by component	'	'	'
Balance at beginning of period	-1.4	-1.4	0.2
Other comprehensive income (loss):	'	'	'
Net change from periodic revaluations	1.2	-1.5	-4.4
Tax benefit (expense)	-0.5	0.6	1.8
Total Other comprehensive income (loss) before reclassifications, net of tax	0.7	-0.9	-2.6
Total Other comprehensive income (loss)	1.6	'	-1.6
Balance at end of period	0.2	-1.4	-1.4
Cash flow hedges | Amount reclassified from accumulated other comprehensive income	'	'	'
Other comprehensive income (loss):	'	'	'
Net amount reclassified to earnings:	1.5	1.5	1.6
Tax benefit (expense)	-0.6	-0.6	-0.6
Total amount reclassified from Accumulated other comprehensive loss, net of tax	0.9	0.9	1
Cash flow hedges | Amount reclassified from accumulated other comprehensive income | Interest rate swaps	'	'	'
Other comprehensive income (loss):	'	'	'
Net amount reclassified to earnings:	1.7	1.9	2.3
Cash flow hedges | Amount reclassified from accumulated other comprehensive income | Fuel commodity swaps	'	'	'
Other comprehensive income (loss):	'	'	'
Net amount reclassified to earnings:	-0.2	-0.4	-0.7
Pension	'	'	'
Changes in accumulated other comprehensive income (loss) by component	'	'	'
Balance at beginning of period	-1.8	-0.5	'
Other comprehensive income (loss):	'	'	'
Unrecognized net actuarial gain (loss)	2.4	-2.1	-0.8
Tax benefit (expense)	-0.7	0.8	0.3
Total Other comprehensive income (loss) before reclassifications, net of tax	1.7	-1.3	-0.5
Total Other comprehensive income (loss)	1.4	-1.3	-0.5
Balance at end of period	-0.4	-1.8	-0.5
Pension | Amount reclassified from accumulated other comprehensive income	'	'	'
Other comprehensive income (loss):	'	'	'
Amortization of net actuarial gain	-0.4	'	'
Tax benefit (expense)	0.1	'	'
Total amount reclassified from Accumulated other comprehensive loss, net of tax	($0.30)	'	'

Acquisitions_and_divestments_D

Acquisitions and divestments (Details)

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

2 Months Ended

12 Months Ended

0 Months Ended

2 Months Ended

0 Months Ended

In Millions, except Share data, unless otherwise specified

Nov. 05, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 28, 2011

Dec. 31, 2011

Dec. 31, 2012

Nov. 05, 2012

Nov. 05, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 30, 2012

Dec. 22, 2012

Nov. 05, 2011

Nov. 05, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2010

Nov. 05, 2011

Dec. 31, 2011

Nov. 05, 2011

Dec. 31, 2012

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Maximum

Minimum

Goshen North

Goshen North

Rockland Wind Farm

Rockland Wind Farm

Rockland Wind Farm

Rockland Wind Farm

Ridgeline

Ridgeline

Ridgeline

Ridgeline

Ridgeline

Meadow Creek

Partnership

Partnership

Partnership

Partnership

Partnership

Partnership

Partnership

Partnership

Rockland Wind Farm

MW

USD ($)

MW

USD ($)

USD ($)

6.00% Debenture due December 2019

Rockland Wind Farm

Rockland Wind Farm

MW

USD ($)

CAD

USD ($)

USD ($)

USD ($)

Maximum

Maximum

Minimum

MW

CAD

USD ($)

Acquisition and divestments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage acquired in entity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

100.00%

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

20.00%

Percentage of ownership interest

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

5.00%

12.50%

'

'

'

50.00%

30.00%

'

'

'

50.00%

30.00%

'

'

'

'

'

'

'

'

'

'

Net generation capacity before increase in ownership (in MW)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Wind power project capacity (in MW)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

124

'

'

'

'

40

'

'

'

'

120

'

'

'

'

'

'

'

'

'

Wind power project capacity, net (in MW)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of Sale of Roxboro and Southport facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

121.4

'

'

'

'

'

'

'

Amount of Sale of Roxboro and Southport facilities per unit of CPILP (in Canadian dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.15

'

'

'

'

'

'

'

Payment for termination of subsidiary management agreements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

'

'

'

'

'

'

'

Transitional services agreement term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'12 months

'

'6 months

'

Average PPA term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'8 years 9 months 18 days

'8 years 9 months 18 days

'

'

'

'

'

'

'

Increased average PPA term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'9 years 1 month 6 days

'9 years 1 month 6 days

'

'

'

'

'

'

'

Cash per unit in exchange of limited partnership units (in Canadian dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

19.4

'

'

'

'

'

'

'

Common shares per unit in exchange of limited partnership units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.3

1.3

'

'

'

'

'

'

'

Cash consideration percentage in exchange of limited partnership units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

73.00%

73.00%

'

'

'

'

'

'

'

Share consideration percentage in exchange of limited partnership units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

27.00%

27.00%

'

'

'

'

'

'

'

Shares issued in connection with acquisition

31,500,215

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,500,000

31,500,000

'

'

'

'

'

'

'

Fair value of consideration transferred:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consideration paid in cash

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

81.3

'

'

'

'

'

601.8

'

'

'

'

'

'

'

'

Consideration paid in equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

407.4

'

'

'

'

'

'

'

'

Total purchase price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

86

'

'

'

'

'

1,009.20

'

'

'

'

'

'

'

'

Acquisition funded by borrowings under revolving credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100

'

'

'

'

'

'

'

'

'

'

'

'

Net proceeds from issuance of convertible debentures, after underwriting discounts and expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

95

'

'

'

'

'

'

'

'

'

'

'

'

Preliminary purchase price allocation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Working capital

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-8.1

'

'

'

'

38

'

'

'

'

'

'

'

'

Property, plant and equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

373.9

'

'

'

'

1,024

'

'

'

'

'

'

'

'

Intangibles

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

528.5

'

'

'

'

'

'

'

'

Deferred tax asset

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.6

'

'

'

'

'

'

'

'

'

'

'

'

'

Other long-term assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

36

'

'

'

'

224.3

'

'

'

'

'

'

'

'

Long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-295.5

'

'

'

'

-621.6

'

'

'

'

'

'

'

'

Interest rate swap derivative

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-21.6

'

'

'

'

'

'

'

'

'

'

'

'

'

Other long-term liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-1.3

'

'

'

'

-129.3

'

'

'

'

'

'

'

'

Deferred tax liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-14.2

'

'

'

'

-164.5

'

'

'

'

'

'

'

'

Minority interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-8

'

'

'

'

'

'

'

'

'

'

'

'

'

Total identifiable net assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

86

'

'

'

'

899.4

'

'

'

'

'

'

'

'

Preferred shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-221.3

'

'

'

'

'

'

'

'

Goodwill

'

296.3

'

'

'

334.7

'

'

'

296.3

334.7

343.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

331.1

'

'

'

'

'

'

'

'

Cash

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

-22.7

'

'

'

'

'

'

'

'

Cash paid, net of cash acquired

'

'

'

'

'

'

'

'

'

'

80.5

591.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

986.5

'

'

'

'

'

'

'

'

Reduction in property, plant and equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23.9

'

'

'

'

'

'

'

'

'

'

'

'

'

Other items to be allocated to identifiable assets acquired and liabilities assumed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of investment in acquiree at the acquisition date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) recognized on the step acquisition

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-7.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

130.7

141.8

139.1

140.1

114

106.3

101.4

118.7

551.7

440.4

93.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

73.8

'

'

'

'

'

'

Net loss

'

'

'

'

'

'

'

'

'

-23.8

-100.3

-35.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.1

'

'

Unaudited pro-forma consolidated results of operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total project revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

694.2

670

'

'

'

'

Net income (loss) attributable to Atlantic Power Corporation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-95.8

-2.5

'

'

'

'

Net income (loss) per share attributable to Atlantic Power Corporation shareholders: Basic (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($0.85)

($0.02)

'

'

'

'

Net income (loss) per share attributable to Atlantic Power Corporation shareholders: Diluted (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($0.85)

($0.02)

'

'

'

'

Purchase price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$12.50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Wind farm capacity under wind project (in MW)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power purchase agreement term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'25 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisitions_and_divestments_D1

Acquisitions and divestments (Details 2) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 05, 2013

Nov. 05, 2013

Apr. 02, 2013

Aug. 31, 2013

Dec. 31, 2013

Apr. 12, 2013

Jan. 30, 2013

Apr. 12, 2013

Apr. 30, 2013

Dec. 07, 2012

Dec. 31, 2013

Sep. 04, 2012

Dec. 31, 2012

Aug. 02, 2012

31-May-12

Feb. 29, 2012

Feb. 16, 2012

Dec. 31, 2011

Dec. 31, 2013

31-May-11

Nov. 05, 2013

2-May-13

Jul. 31, 2012

Mar. 30, 2012

Dec. 31, 2012

Dec. 31, 2013

Jan. 31, 2012

Cadillac and Piedmont Projects

Piedmont

Gregory

Gregory

Gregory

Auburndale, Lake and Pasco

Auburndale, Lake and Pasco

Auburndale, Lake and Pasco

Path 15

Delta-Person

Delta-Person

Badger Creek

Badger Creek

Badger Creek

Primary Energy Recycling Corporation

Primary Energy Recycling Corporation

Primary Energy Recycling Corporation

Onondaga Renewables

Onondaga Renewables

Topsham

Rollcast

Canadian Hills

Canadian Hills

Canadian Hills

Canadian Hills

Canadian Hills

Canadian Hills

Expected

item

MW

Acquisition and divestments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest sold (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

100.00%

'

'

'

'

'

Value of asset management contracts assigned

'

'

'

$0.50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage acquired in entity

'

'

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

48.00%

'

'

51.00%

Ownership interest (as a percent)

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding debt forgive

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.5

'

'

'

'

'

'

Amount paid to minority owner

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

Gain on sale of recorded in other income, net

-32.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

Percentage of ownership interest

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

'

'

'

50.00%

'

'

14.30%

'

50.00%

'

'

'

'

99.00%

'

99.00%

'

Wind power project capacity (in MW)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300

Percentage of retained interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

Project-level construction financing facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

310

'

'

'

Construction loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

290

'

'

'

Letter of credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20

'

'

'

Letter of credit facility, term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

Investment in equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

190

'

'

'

'

Tax equity investments received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

225

'

'

Number of institutional tax equity investors by whom tax equity investments received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

Own tax equity investment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

44

'

'

44

'

'

Short-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

265

0

'

Proceeds from sale of remaining tax equity ownership

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

42.1

'

'

'

'

'

Tax equity interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

269

'

'

'

'

'

Total price

'

'

'

'

'

274.2

'

'

'

140

'

56

'

'

'

'

'

'

30.2

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of equity method investment

'

'

'

'

'

'

30.4

30.4

'

'

'

'

'

'

'

'

'

0.6

'

'

'

'

0

'

'

'

'

'

'

'

Expected proceeds from sale

'

'

'

'

'

34.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale to be held in escrow account

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term Of Escrow Account

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net cash proceeds from sale

182.6

'

'

'

'

'

'

'

92

'

117

52

'

9

3.7

'

'

'

'

'

'

'

8.5

'

'

'

'

'

'

'

Distributions from unconsolidated affiliates

40.9

38.4

21.9

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt transferred with the sale of business

'

'

'

'

'

'

'

'

'

'

'

137.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding balance of senior credit facility

'

'

'

'

'

'

'

'

64.1

'

64.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment charge on pending sale

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

1.5

'

'

'

'

'

'

'

'

'

Entity's common membership interest to be purchased in equity method investee (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,462,830.33

'

'

'

'

'

'

'

'

'

'

'

Price of entity's common membership interest in equity method investee

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24.2

'

'

'

'

'

'

'

'

'

'

'

Management termination fee

'

'

'

'

'

'

'

'

'

'

'

$4

'

'

'

'

'

'

$6

'

'

'

'

'

'

'

'

'

'

'

Equity_method_investments_in_u2

Equity method investments in unconsolidated affiliates (Details) (USD $)

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Nov. 05, 2012

Dec. 31, 2012

Dec. 30, 2012

Frederickson

Frederickson

Frederickson

Orlando Cogen, LP

Orlando Cogen, LP

Orlando Cogen, LP

Koma Kulshan Associates

Koma Kulshan Associates

Koma Kulshan Associates

Onondaga Rewables LLC

Onondaga Rewables LLC

Onondaga Rewables LLC

Chambers Cogen, LP

Chambers Cogen, LP

Chambers Cogen, LP

Delta-Person, LP

Idaho Wind Partners 1, LLC

Idaho Wind Partners 1, LLC

Idaho Wind Partners 1, LLC

Selkirk Cogen Partners, LP

Selkirk Cogen Partners, LP

Selkirk Cogen Partners, LP

Goshen North

Goshen North

Gregory Power Partners, LP

Gregory Power Partners, LP

Gregory Power Partners, LP

Gregory Power Partners, LP

Other

Other

Other

Rockland Wind Farm

Rockland Wind Farm

Rockland Wind Farm

Rockland Wind Farm

Ridgeline Energy LLC

Ridgeline Energy LLC

Equity method investments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

'

'

50.00%

'

'

50.00%

'

'

49.80%

'

'

50.00%

'

'

40.00%

'

'

40.00%

27.60%

'

'

18.50%

'

'

12.50%

'

'

'

'

'

'

'

'

50.00%

30.00%

50.00%

30.00%

Carrying value

$394.30

$428.70

'

$153.90

$167.70

'

$14.30

$19.90

'

$5.80

$6.40

'

'

$0.20

'

$153.70

$154.30

'

'

$33.20

$34.70

'

$24.40

$33.70

'

$9

$9

'

'

$2.80

'

'

'

'

'

'

'

'

Deficit in earnings (loss) of equity method investments

26.9

15.2

6.4

2.1

0.9

0.4

3.3

3.2

0.9

0.3

0.5

0.5

-0.3

-0.4

-1.8

9.6

17.1

7.7

'

-0.3

-0.2

-1.6

8.7

7.6

-0.4

1.4

'

'

1.6

-0.7

0.5

0.5

-4.8

0.2

-8

'

'

'

Distributions from equity method investments

-40.9

-38.4

-21.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deficit in earnings (loss) of equity method investments, net of distributions

-14

-23.2

-15.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of equity method investment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$30.40

$30.40

'

'

'

'

'

'

'

'

'

Equity_method_investments_in_u3

Equity method investments in unconsolidated affiliates (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assets	'	'	'
Total assets	$574	$644.50	$700.70
Liabilities	'	'	'
Total liabilities	179.7	215.8	226.3
Operating results	'	'	'
Project revenue	204.4	216.6	195.7
Project expenses	169.8	174.2	174.4
Project other income (expense)	-7.7	-27.2	-14.9
Project income (loss)	26.9	15.2	6.4
Chambers Cogen, LP	'	'	'
Assets	'	'	'
Current assets	11.8	16.1	9.9
Non-Current assets	224	235.2	245.8
Liabilities	'	'	'
Current liabilities	4.4	15.2	16
Non-Current liabilities	77.7	81.8	96
Operating results	'	'	'
Project revenue	52.7	58.1	49.3
Project expenses	40.6	39.1	39.4
Project other income (expense)	-2.5	-1.9	-2.2
Project income (loss)	9.6	17.1	7.7
Selkirk Cogen Partners, LP	'	'	'
Assets	'	'	'
Current assets	12.9	12.9	15.9
Non-Current assets	14.1	26	47.7
Liabilities	'	'	'
Current liabilities	2.3	4.8	14.7
Non-Current liabilities	0.3	0.3	1.5
Operating results	'	'	'
Project revenue	50.5	48.7	54.6
Project expenses	40.3	42.4	49.6
Project other income (expense)	-1.5	1.3	-5.4
Project income (loss)	8.7	7.6	-0.4
Other	'	'	'
Assets	'	'	'
Current assets	24.6	32	22.3
Non-Current assets	286.6	322.3	359.1
Liabilities	'	'	'
Current liabilities	13.9	16.4	19.1
Non-Current liabilities	81.1	97.3	79
Operating results	'	'	'
Project revenue	101.2	109.8	91.8
Project expenses	88.9	92.7	85.4
Project other income (expense)	-3.7	-26.6	-7.3
Project income (loss)	$8.60	($9.50)	($0.90)

Inventory_Details

Inventory (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Inventory	'	'
Parts and other consumables	$11.30	$8.60
Fuel	4.7	8.3
Total inventory	$16	$16.90

Property_plant_and_equipment_D

Property, plant and equipment (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	$1,988.50	$2,135.10	'
Less accumulated depreciation	-175.1	-79.6	'
Property, plant and equipment, net	1,813.40	2,055.50	'
Depreciation expense	106	58.6	13.2
Maximum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'45 years	'	'
Land	'	'	'
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	5.9	7.3	'
Office equipment, machinery and other	'	'	'
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	3.3	2.9	'
Office equipment, machinery and other | Minimum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'3 years	'	'
Office equipment, machinery and other | Maximum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'10 years	'	'
Leasehold improvements	'	'	'
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	0.4	0.4	'
Leasehold improvements | Minimum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'7 years	'	'
Leasehold improvements | Maximum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'15 years	'	'
Asset retirement obligation	'	'	'
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	34.8	35.7	'
Asset retirement obligation | Minimum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'1 year	'	'
Asset retirement obligation | Maximum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'42 years	'	'
Plant in service	'	'	'
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	1,938.40	1,895	'
Plant in service | Minimum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'1 year	'	'
Plant in service | Maximum	'	'	'
Property, plant and equipment	'	'	'
Depreciable Lives	'45 years	'	'
Construction in progress	'	'	'
Property, plant and equipment	'	'	'
Property, plant and equipment, gross	$5.70	$193.70	'

Goodwill_Details

Goodwill (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Nov. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Mar. 31, 2010

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2011

Jun. 30, 2013

item

Partnership

Rollcast

Rollcast

East

East

West

West

Un-allocated Corporate

Un-allocated Corporate

Un-allocated Corporate

Un-allocated Corporate

Rollcast

Goodwill

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of lease and steam projects

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill recorded in connection with the acquisition

'

'

'

'

'

$331.10

$3.50

'

'

'

'

'

'

'

'

'

Changes in the carrying amount of goodwill

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at the beginning of the period

'

'

334.7

343.6

'

'

'

'

138.6

138.6

192.6

201.5

'

3.5

3.5

'

Reclass to assets held for sale

'

'

'

-8.9

'

'

'

'

'

'

'

-8.9

'

'

'

'

Impairment of goodwill

0

34.9

34.9

'

'

'

'

'

-30.8

'

-4.1

'

3.5

-3.5

'

3.5

Impairment of goodwill

'

'

-38.4

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at the end of the period

'

'

296.3

334.7

343.6

'

'

'

107.8

138.6

188.5

192.6

'

'

3.5

'

Capitalized development costs at Rollcast related to the Greenway development project written-off

'

'

$59.60

$58.30

$10.20

'

'

$1.40

'

'

'

'

'

'

'

'

Power_purchase_agreements_and_2

Power purchase agreements and other intangible assets and liabilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of intangible assets	'	'	'
Gross balance at the end of the period	$602.20	$597.10	'
Less: accumulated amortization	-140.1	-76.9	'
Foreign currency translation adjustment	-10.6	4.7	'
Net balance at the end of the period	451.5	524.9	'
Gross balances at the end of the period	-48.5	-47.9	'
Less: accumulated amortization	7.8	4.5	'
Foreign currency translation adjustment	2	-0.6	'
Net balance at the end of the period	-38.7	-44	'
Amortization expense of intangible assets	59.6	58.3	10.2
Power Purchase Agreements	'	'	'
Components of intangible assets	'	'	'
Gross balance at the end of the period	597.4	590.9	'
Less: accumulated amortization	-139.8	-76.9	'
Foreign currency translation adjustment	-10.6	4.7	'
Net balance at the end of the period	447	518.7	'
Gross balances at the end of the period	-35.9	-35.3	'
Less: accumulated amortization	5.3	2.9	'
Foreign currency translation adjustment	2	-0.6	'
Net balance at the end of the period	-28.6	-33	'
Amortization expense of intangible assets	60.8	59.5	11.6
Development Costs	'	'	'
Components of intangible assets	'	'	'
Gross balance at the end of the period	4.8	6.2	'
Less: accumulated amortization	-0.3	'	'
Net balance at the end of the period	4.5	6.2	'
Fuel Supply Agreements	'	'	'
Components of intangible assets	'	'	'
Gross balances at the end of the period	-12.6	-12.6	'
Less: accumulated amortization	2.5	1.6	'
Net balance at the end of the period	-10.1	-11	'
Amortization expense of intangible assets	($1.20)	($1.20)	($1.40)

Power_purchase_agreements_and_3

Power purchase agreements and other intangible assets and liabilities (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Power Purchase Agreements	'
Estimated future amortization expense	'
2014	$58.40
2015	55
2016	55
2017	55.1
2018	47.3
Weighted average remaining amortization period related to our intangible assets	'
Weighted average remaining amortization period	'9 years
Fuel Supply Agreements	'
Estimated future amortization expense	'
2014	-1.2
2015	-1.2
2016	-1.2
2017	-1.2
2018	($1.20)
Weighted average remaining amortization period related to our intangible assets	'
Weighted average remaining amortization period	'9 years

Other_longterm_liabilities_Det

Other long-term liabilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Other long-term liabilities	'	'
Asset retirement obligations	$57.70	$57.80
Net pension liability	0.8	4.8
Deferred revenue	4	4.9
Other	2.9	3.9
Other long-term liabilities	65.4	71.4
Movement in asset retirement obligations in acquisition of CPILP	'	'
Asset retirement obligations beginning of year	57.8	'
Accretion of asset retirement obligations	1.6	'
Translation adjustments	-1.7	'
Asset retirement obligations, end of year	$57.70	'

Longterm_debt_Details

Long-term debt (Details)

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 05, 2011

Dec. 31, 2013

Dec. 31, 2012

Feb. 26, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Feb. 26, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Apr. 19, 2013

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Feb. 14, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Feb. 14, 2014

Feb. 14, 2014

Feb. 14, 2014

Aug. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 02, 2013

Dec. 31, 2013

Jul. 31, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Aug. 02, 2013

Feb. 24, 2014

Mar. 31, 2014

Feb. 26, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 26, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 24, 2014

Feb. 26, 2014

Feb. 26, 2014

Dec. 31, 2009

Feb. 26, 2014

USD ($)

USD ($)

USD ($)

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due 2018

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due June 2036

Senior unsecured notes, due July 2014

Senior unsecured notes, due July 2014

Senior unsecured notes, due July 2014

Senior unsecured notes, due July 2014

Series A senior unsecured notes, due August 2015

Series A senior unsecured notes, due August 2015

Series B senior unsecured notes, due August 2017

Series B senior unsecured notes, due August 2017

Epsilon Power Partners term facility, due 2019

Epsilon Power Partners term facility, due 2019

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Cadillac term loan, due 2025

Piedmont bridge loan, due 2014

Piedmont bridge loan, due 2014

Piedmont bridge loan, due 2014

Piedmont bridge loan, due 2014

Piedmont bridge loan, due 2014

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Meadow Creek term loan, due 2024

Construction loan

Cash grant loan

Cash grant loan

Rockland term loan, due 2027

Rockland term loan, due 2027

Other long-term debt

Other long-term debt

Other long-term debt

Other long-term debt

Term loan due August 2018

Term loan due August 2018

Term loan due August 2018

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

Prior credit facility

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New Senior Secured Credit Facilities

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New term loan facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

New revolving credit facility

Existing notes

5.87% senior guaranteed notes, Series A, due August 15, 2017

5.97% senior guaranteed notes, Series B, due August 15, 2019

6.50% convertible debentures

6.50% convertible debentures

USD ($)

USD ($)

USD ($)

Subsequent Event

USD ($)

CAD

USD ($)

CAD

USD ($)

USD ($)

Curtis Palmer

Subsequent Event

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

USD ($)

Subsequent Event

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

London Interbank Offered Rate (LIBOR)

London Interbank Offered Rate (LIBOR)

London Interbank Offered Rate (LIBOR)

USD ($)

Minimum

Maximum

London Interbank Offered Rate (LIBOR)

US Prime Rate

Canadian Prime Rate

USD ($)

USD ($)

Minimum

Maximum

US Prime Rate

US Prime Rate

US Prime Rate

Eurocurrency LIBOR Rate

Eurocurrency LIBOR Rate

Eurocurrency LIBOR Rate

Canadian Prime Rate

Canadian Prime Rate

Canadian Prime Rate

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Canadian Prime Rate

Adjusted Eurodollar Rate

Base Rate

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Adjusted Eurodollar Rate

Adjusted Eurodollar Rate

Base Rate

Subsequent Event

Subsequent Event

Adjusted Eurodollar Rate

Base Rate

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

USD ($)

USD ($)

Curtis Palmer

USD ($)

Subsequent Event

Subsequent Event

Subsequent Event

USD ($)

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

The Partnership

The Partnership

The Partnership

The Partnership

The Partnership

Minimum

Maximum

Subsequent Event

Subsequent Event

Subsequent Event

The Partnership

The Partnership

Minimum

Maximum

Subsequent Event

Subsequent Event

Subsequent Event

The Partnership

The Partnership

Subsequent Event

Subsequent Event

The Partnership

USD ($)

USD ($)

USD ($)

USD ($)

Minimum

Maximum

USD ($)

USD ($)

Effect of change of control

Repayment of loan facility within one year

The Partnership

The Partnership

The Partnership

The Partnership

The Partnership

USD ($)

USD ($)

The Partnership

The Partnership

The Partnership

Minimum

The Partnership

USD ($)

USD ($)

The Partnership

The Partnership

USD ($)

USD ($)

USD ($)

The Partnership

Long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total debt

$1,471

'

'

$460

$460

$460

'

$197.40

210

$211.10

210

$190

$190

$190

'

$150

$150

$75

$75

$30.50

$33.50

$35.40

$37.80

'

'

'

'

$76.60

$127.40

'

$169.80

$208.70

'

'

$169.80

'

$56.50

$85.30

$86.50

$1

$0.30

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Less current maturities

-216.2

-121.2

'

'

'

'

'

'

'

'

'

190

'

'

'

'

'

'

'

5

3

2

2.4

'

'

'

'

12.6

55.1

'

4.9

59.5

'

'

'

'

'

1.5

1.2

0.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt

1,254.80

1,459.10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate (as a percent)

'

'

'

9.00%

9.00%

'

'

6.00%

6.00%

'

'

5.90%

'

5.90%

'

5.90%

'

6.00%

'

7.40%

'

'

'

6.00%

8.00%

'

'

'

'

'

'

'

2.90%

5.60%

'

'

'

6.40%

'

'

'

5.50%

6.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.87%

5.97%

6.50%

6.50%

Variable interest rate basis

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'Libor

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'

'

'

'

'

'

'LIBOR

'U.S. Prime Rate

'Canadian Prime Rate

'

'

'

'

'

'US Prime Rate

'

'

'Eurocurrency LIBOR Rate

'

'

'Cdn. Prime Rate

'

'

'

'

'

'

'

'

'

'Canadian Prime Rate

'Adjusted Eurodollar Rate

'Base Rate

'

'

'

'

'Adjusted Eurodollar Rate

'

'Base Rate

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

3.00%

4.25%

'

'

'

'

'

'

'

'

2.75%

4.75%

'

2.75%

4.75%

'

2.75%

4.75%

'

'

'

'

'

2.75%

3.75%

'

'

'

'

'

'

'

'

1.00%

'

'

'

3.75%

2.75%

'

'

'

'

'

Bridge loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Construction loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery as a percentage of capital cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount received under the 1603 federal grant program

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

49.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayment of debt from proceeds from 1603 grant with U.S. Treasury

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51

'

'

'

'

'

'

'

'

49

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300

'

'

'

'

'

150

'

300

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

'

'

'

210

'

'

'

210

'

'

'

'

Contribution to cover shortfall resulting from the federal sequester on spending

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.5

'

'

'

'

'

'

'

'

4.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal amount of debt repaid

'

'

'

'

'

'

150

'

'

'

'

'

'

'

190

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150

75

'

46

Make-whole premiums

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of debt converted to term loan due August 2018

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

68.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate of converted debt (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.50%

4.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of par value at which debt was issued

'

'

'

97.47%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contribution to cover shortfall resulting from lower grant-eligible costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross proceeds from senior notes

'

'

'

448

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity before amendment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum capacity to be utilized for letter of credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200

'

'

'

'

'

200

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt to EBITDA ratio, restriction on payment of dividend to shareholders

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.25

'

'

'

'

'

'

7.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate amount of sublimit available for borrowings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash collateralized required if letters of credit and borrowings outstanding under the amended credit facility exceeded $125 million

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Threshold limit of amended credit facility for required cash collateralized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrestricted cash and cash equivalents

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consolidated Total Net Debt to Consolidated EBITDA

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.5

'

'

'

'

'

'

7.5

'

'

'

7.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consolidated Total Net Debt to Consolidated EBITDA Over Time

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700.00%

'

'

'

'

'

'

700.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consolidated EBITDA to Consolidated Interest Expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.25

'

'

'

'

'

'

2.25

'

'

1.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment fee (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.50%

'

'

'

'

'

'

1.50%

'

0.75%

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

'

'

'

'

'

'

'

'

Period preceding the maturity of debt for voluntarily prepayment or repurchase of any outstanding debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period prior to expiration date of facility letters of credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 days

'

'

'

'

'

'

'

'

Debt service reserve requirement period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage ratio of total debt to adjusted EBITDA in 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage ratio of total debt to adjusted EBITDA in 2021

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio of adjusted EBITDA to cash interest expense in 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio of adjusted EBITDA to cash interest expense in 2021

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price as percentage of principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

101.00%

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Mandatory prepayment as a percentage of excess cash flows

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount drawn under facility

20.8

291.9

100.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of credit issued but not drawn

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

97.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

144

'

'

'

'

'

'

'

Debt service reserve requirement amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution amount to be received from proceeds of issuance of debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120

125

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of noteholders who approved the issuer's solicitation of a waiver of the prepayment notice provisions

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal payments on the maturities of debt due in next five years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2014

216.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2015

170.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2016

19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2017

96.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2018

529.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Thereafter

439.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total debt

$1,471

'

'

$460

$460

$460

'

$197.40

210

$211.10

210

$190

$190

$190

'

$150

$150

$75

$75

$30.50

$33.50

$35.40

$37.80

'

'

'

'

$76.60

$127.40

'

$169.80

$208.70

'

'

$169.80

'

$56.50

$85.30

$86.50

$1

$0.30

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Convertible_debentures_Details

Convertible debentures (Details)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2009

Dec. 31, 2013

Dec. 17, 2009

Dec. 31, 2013

Dec. 31, 2012

Dec. 17, 2009

Oct. 20, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Oct. 20, 2010

Jul. 05, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 11, 2012

Dec. 31, 2013

Dec. 31, 2012

USD ($)

USD ($)

USD ($)

6.25% 2006 Debentures due 2011

6.25% 2006 Debentures due 2011

6.25% 2006 Debentures due 2011

6.5% Debentures due October 2014

6.5% Debentures due October 2014

6.5% Debentures due October 2014

6.5% Debentures due October 2014

6.25% Debentures due March 2017

6.25% Debentures due March 2017

6.25% Debentures due March 2017

6.25% Debentures due March 2017

6.25% Debentures due March 2017

5.6% Debentures due June 2017

5.6% Debentures due June 2017

5.6% Debentures due June 2017

5.6% Debentures due June 2017

5.6% Debentures due June 2017

5.75% Debentures due June 2019

5.75% Debentures due June 2019

5.75% Debentures due June 2019

6.00% Debenture due December 2019

6.00% Debenture due December 2019

6.00% Debenture due December 2019

USD ($)

CAD

CAD

CAD

USD ($)

USD ($)

CAD

USD ($)

USD ($)

USD ($)

CAD

USD ($)

USD ($)

USD ($)

CAD

CAD

USD ($)

USD ($)

USD ($)

CAD

USD ($)

USD ($)

Movement in convertible debentures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at the beginning of the period

$424.20

$189.60

'

'

'

'

'

$45.10

$44.10

'

'

'

$67.80

$66.30

'

'

$81

$79.20

'

'

'

'

$130

'

$100.30

'

Issuance of convertible debentures

'

230.6

'

52.8

'

'

'

'

'

'

'

82.1

'

'

'

78.9

'

'

'

'

'

130

'

'

'

100.6

Foreign exchange loss (gain) (Note 13)

-27.4

0.5

13.8

'

'

'

'

-3

1

'

'

'

-4.4

1.5

'

'

-5.3

1.8

'

'

'

'

'

'

-6.3

-0.3

Balance at the end of the period

363.1

424.2

189.6

'

'

'

'

42.1

45.1

'

'

'

63.4

67.8

'

'

75.7

81

'

'

'

130

130

'

94

100.3

Aggregate principal amount of convertible debentures issued

'

'

'

'

'

60

'

'

'

'

'

'

'

'

86.3

'

'

'

'

80.5

130

'

'

100

'

'

Convertible debentures stated interest rate percentage

'

'

'

'

'

6.25%

'

'

'

6.50%

'

'

'

'

6.25%

'

'

'

'

5.60%

5.75%

'

'

6.00%

'

'

Gross proceeds from issuance of convertible debenture

'

230.6

'

52.8

'

'

'

'

'

'

'

82.1

'

'

'

78.9

'

'

'

'

'

130

'

'

'

100.6

Conversion rate of the debentures (in Shares per Dollar)

'

'

'

0.0806452

'

'

'

'

'

'

'

'

0.0769231

'

'

'

0.0552486

'

'

'

0.057971

'

'

0.0689655

'

'

Conversion price of shares (in dollars per share)

'

'

'

'

12.4

'

'

'

'

'

13

'

'

'

'

'

'

'

18.1

'

$17.25

'

'

14.5

'

'

Principal amount converted to equity

'

'

26.4

'

'

'

15.2

'

'

'

18.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares issued on conversion

'

'

'

'

'

'

1.2

'

'

'

'

'

1.4

'

'

'

'

'

'

'

'

'

'

'

'

'

Net proceeds from issuance convertible debentures issued, after underwriting discounts and expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

124

'

'

95.5

'

'

Aggregate interest expenses

$24.20

$12.10

$12.10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_value_of_financial_instru2

Fair value of financial instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair value of financial instruments	'	'
Restricted cash	$114.20	$28.60
Derivative assets current	0.2	9.5
Derivative assets non-current	13	11.1
Derivative liabilities current	28.5	33
Derivative liabilities non-current	76.1	118.1
Carrying Amount	'	'
Fair value of financial instruments	'	'
Cash and cash equivalents	158.6	60.2
Restricted cash	114.2	28.6
Derivative assets current	0.2	9.5
Derivative assets non-current	13	11.1
Derivative liabilities current	28.5	33
Derivative liabilities non-current	76.1	118.1
Revolving credit facility and long-term debt, including current portion	1,471	1,647.30
Convertible debentures	405.2	424.2
Fair Value	'	'
Fair value of financial instruments	'	'
Cash and cash equivalents	158.6	60.2
Restricted cash	114.2	28.6
Derivative assets current	0.2	9.5
Derivative assets non-current	13	11.1
Derivative liabilities current	28.5	33
Derivative liabilities non-current	76.1	118.1
Revolving credit facility and long-term debt, including current portion	1,435.20	1,701.80
Convertible debentures	$281.10	$416.70

Fair_value_of_financial_instru3

Fair value of financial instruments (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assets:	'	'	'
Restricted cash	$114.20	$28.60	'
Liabilities:	'	'	'
Foreign exchange gain	27.4	-0.5	-13.8
Credit valuation adjustments	'	'	'
Liabilities:	'	'	'
Net increase in fair value	11.1	18.4	'
Pre-tax increase in other comprehensive income	0.5	1.1	'
Increase in change in fair value of derivatives	10.6	13.8	'
Credit valuation adjustments | Foreign currency forward contracts	'	'	'
Liabilities:	'	'	'
Foreign exchange gain	'	3.6	'
Recurring | Level 1	'	'	'
Assets:	'	'	'
Cash and cash equivalents	158.6	60.2	'
Restricted cash	114.2	28.6	'
Total	272.8	88.8	'
Recurring | Level 2	'	'	'
Assets:	'	'	'
Derivative instruments asset	13.2	20.6	'
Total	13.2	20.6	'
Liabilities:	'	'	'
Derivative instruments liability	104.6	151.1	'
Total	104.6	151.1	'
Recurring | Total	'	'	'
Assets:	'	'	'
Cash and cash equivalents	158.6	60.2	'
Restricted cash	114.2	28.6	'
Derivative instruments asset	13.2	20.6	'
Total	286	109.4	'
Liabilities:	'	'	'
Derivative instruments liability	104.6	151.1	'
Total	$104.60	$151.10	'

Accounting_for_Derivative_inst1

Accounting for Derivative instruments and hedging activities (Details)

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Feb. 14, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

USD ($)

Piedmont bridge loan, due 2014

Piedmont bridge loan, due 2014

Swaption interest rate until December 31, 2024

Swaption interest rate from December 2024 to December 2030

Natural gas swaps

Natural gas swaps

Natural gas swaps

Natural gas swaps during 2014 and 2015

Natural gas swaps during 2016 and 2017

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Interest rate swaps

Foreign currency forward contracts

item

USD ($)

USD ($)

Meadow Creek Project

Meadow Creek Project

MMBTU

MMBTU

Orlando project

Orlando project

Orlando project

Epsilon

Rockland Wind Farm

Piedmont

Piedmont

Swaption interest rate until February 15, 2015

Swaption interest rate from February 16, 2015 to February 15, 2019

Swaption interest rate from February 16, 2019 to February 15, 2023

Swaption interest rate after February 15, 2023

Swaption interest rate until February 29, 2016

Swaption interest rate from February, 2016 to November, 2017

Swaption interest rate from November, 2017 to November, 2030

Swaption interest rate until December 31, 2026

Swaption interest rate from December 31, 2026 to December 31, 2031

CAD

MMBTU

MMBTU

item

Subsequent event

Subsequent event

Cadillac Project

Cadillac Project

Cadillac Project

Cadillac Project

Piedmont

Piedmont

Piedmont

Rockland Wind Farm

Rockland Wind Farm

USD ($)

Piedmont bridge loan, due 2014

USD ($)

Accounting for derivative instruments and hedging activities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Number of Contracts Designated as Cash Flow Hedges

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instruments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount (in Mmbtu)

'

'

'

'

'

5,600,000

10,600,000

'

3,200,000

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of the entity's share in required natural gas purchases hedge

'

'

'

'

'

'

'

'

64.00%

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Swaption interest rate (as a percent)

'

'

'

'

'

'

'

'

'

'

7.37%

'

'

'

6.02%

6.14%

6.26%

6.38%

1.70%

4.47%

4.47%

'

'

'

Total debt

$1,471

$76.60

$127.40

'

'

'

'

'

'

'

'

'

'

$68.50

'

'

'

'

'

'

'

'

'

'

Interest expense related to derivatives

'

'

'

'

'

'

'

'

'

'

'

'

0.6

'

'

'

'

'

'

'

'

'

'

'

Swap percentage

'

'

'

2.30%

7.20%

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

4.20%

7.80%

'

Number of tranches

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin, low end of range (as a percent)

'

'

'

2.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.50%

'

'

2.30%

'

'

Applicable margin, high end of range (as a percent)

'

'

'

3.30%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.75%

'

'

2.80%

'

'

Percentage of floating rate debt converted to a fixed interest rate

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

Swaption interest rate after addition of applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.47%

'

'

'

'

Percentage of expected dividend, long-term debt and convertible debenture interest payments hedge

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

74.00%

Notional amount through December 2015

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

34.9

Exchange rate through December 2015

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.108

Accounting_for_Derivative_inst2

Accounting for Derivative instruments and hedging activities (Details 2)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Natural gas swaps	Natural gas swaps	Gas purchase agreements	Gas purchase agreements	Interest rate swaps	Interest rate swaps	Foreign currency forwards	Foreign currency forwards
	MMBTU	MMBTU	gigajoule	gigajoule	USD ($)	USD ($)	CAD	CAD
Derivative instruments	'	'	'	'	'	'	'	'
Volume of forecasted transactions	5,600,000	10,600,000	41,100,000	49,800,000	'	'	'	'
Volume of forecasted transactions, (in dollars)	'	'	'	'	$161.20	$172	34.9	176.6

Accounting_for_Derivative_inst3

Accounting for Derivative instruments and hedging activities (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair value of derivative instruments	'	'
Derivative Assets	$13.70	$20.80
Derivative Liabilities	105.1	151.3
Derivative instruments designated as cash flow hedges	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	3.9	6.5
Derivative instruments designated as cash flow hedges | Interest rate swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	1.3	1.3
Derivative instruments designated as cash flow hedges | Interest rate swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	2.6	5.2
Derivative instruments not designated as cash flow hedges	'	'
Fair value of derivative instruments	'	'
Derivative Assets	13.7	20.8
Derivative Liabilities	101.2	144.8
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	7.3	7.3
Derivative instruments not designated as cash flow hedges | Interest rate swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	11.5	0.1
Derivative Liabilities	8.1	27.7
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	0.5	9.5
Derivative Liabilities	0.7	'
Derivative instruments not designated as cash flow hedges | Foreign currency forward contracts | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	1.2	11
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	0.3	'
Derivative Liabilities	1.3	'
Derivative instruments not designated as cash flow hedges | Natural gas swaps | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Assets	'	0.1
Derivative Liabilities	3.5	3.9
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Current	'	'
Fair value of derivative instruments	'	'
Derivative Assets	0.2	0.1
Derivative Liabilities	18.4	24.5
Derivative instruments not designated as cash flow hedges | Gas purchase agreements | Long-term	'	'
Fair value of derivative instruments	'	'
Derivative Liabilities	$61.90	$81.40

Accounting_for_Derivative_inst4

Accounting for Derivative instruments and hedging activities (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in the accumulated other comprehensive income (loss)	'	'	'
Accumulated OCI balance at beginning of period	($1.40)	($1.40)	$0.20
Change in fair value of cash flow hedges	0.7	-0.9	-2.6
Realized from OCI during the period	0.9	0.9	1
Accumulated OCI balance at end of period	0.2	-1.4	-1.4
Gains expected to be realized from OCI in the next 12 months, net of $0.6 tax for the year ended December 31, 2013	1	'	'
Tax effect of gains (losses) expected to be realized from OCI in the next 12 months	0.6	'	'
Interest Rate Swaps	'	'	'
Changes in the accumulated other comprehensive income (loss)	'	'	'
Accumulated OCI balance at beginning of period	-1.5	-1.6	-0.4
Change in fair value of cash flow hedges	0.7	-0.9	-2.6
Realized from OCI during the period	1	1.1	1.4
Accumulated OCI balance at end of period	0.2	-1.5	-1.6
Gains expected to be realized from OCI in the next 12 months, net of $0.6 tax for the year ended December 31, 2013	1	'	'
Natural Gas Swaps	'	'	'
Changes in the accumulated other comprehensive income (loss)	'	'	'
Accumulated OCI balance at beginning of period	0.1	0.2	0.6
Realized from OCI during the period	-0.1	-0.2	-0.4
Accumulated OCI balance at end of period	'	$0.10	$0.20

Accounting_for_Derivative_inst5

Accounting for Derivative instruments and hedging activities (Details 5) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 28, 2014

Feb. 28, 2014

Feb. 28, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Natural gas swaps

Interest rate swaps

Foreign currency forward contracts

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Derivative instruments not designated as cash flow hedges

Subsequent Event

Subsequent Event

Subsequent Event

Natural gas swaps

Natural gas swaps

Natural gas swaps

Gas purchase agreements

Gas purchase agreements

Interest rate swaps

Interest rate swaps

Interest rate swaps

Foreign currency forward contracts

Foreign currency forward contracts

Foreign currency forward contracts

Impact of derivative instruments on the consolidated statements of operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Realized (gains) and losses of derivative instruments

'

'

'

'

'

'

'

'

'

'

'

'

$56.50

$43.50

$9.90

$4.60

$4.20

($14.40)

($18.50)

$5.20

Amount paid for termination of contracts

'

'

'

4

2.6

0.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Change in fair value of derivative instruments

$49.50

($59.30)

($14.60)

'

'

'

$49.50

($59.30)

($14.60)

($0.70)

($1.20)

($2.40)

$19.20

($57)

$31

($1.10)

($12.20)

$19.40

$12

$14.20

Income_taxes_Details

Income taxes (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of income tax expenses (benefit)	'	'	'
Current income tax expense (benefit)	$7.80	$6	($1.20)
Deferred tax benefit	-27.3	-34.1	-9.9
Total income tax benefit, net	-19.5	-28.1	-11.1
Canadian enacted statutory rate (as a percent)	26.00%	25.00%	26.50%
Reconciliation of income taxes	'	'	'
Computed income taxes at Canadian statutory rate	-9.7	-36.2	-22
Decreases resulting from:	'	'	'
Operating countries with different income tax rate	-2.9	-8.5	-10.6
Income tax expense (benefit) after adjustments for operating countries with different income tax rates	-12.6	-44.7	-32.6
Change in valuation allowance	12.1	20.2	21.7
Income tax expense (benefit) after adjustments for operating countries with different income tax rates and valuation allowance	-0.5	-24.5	-10.9
Dividend withholding tax and other cash taxes	3.7	5.9	0.4
Foreign exchange	-9.9	1.5	-0.1
Permanent differences	'	-6.5	-1.5
Non-deductible acquisition costs	'	0.6	4.3
Non-deductible interest expense	'	'	2.1
Changes in tax rates	-4.1	1.8	'
Federal grant	-18.9	'	-6.6
Production tax credits	-4.5	'	'
Change in estimates of tax basis of equity method investments	-1.4	-5.1	2.2
Goodwill impairment	13.6	'	'
Other	2.5	-1.8	-1
Total other reconciliation items	-19	-3.6	-0.2
Total income tax benefit, net	-19.5	-28.1	-11.1
Deferred tax assets:	'	'	'
Loss carryforwards	254.1	130.2	'
Other accrued liabilities	0.4	10.9	'
Finance and share issuance costs	6.7	8.3	'
Disallowed interest carryforward	1.7	2.2	'
Derivative contracts	27.8	3.5	'
Other	8	6.1	'
Total deferred tax assets	298.7	161.2	'
Valuations allowance	-128.1	-116	'
Net deferred tax assets	170.6	45.2	'
Deferred tax liabilities:	'	'	'
Intangible assets	-74.2	-113.3	'
Property, plant and equipment	-194.8	-94.7	'
Other long-term investments	-13.1	-1.2	'
Total deferred tax liabilities	-282.1	-209.2	'
Net deferred tax liability	-111.5	-164	'
Net deferred tax position	'	'	'
Long-term deferred tax liabilities	-111.5	-164	'
Net deferred tax liability	($111.50)	($164)	'

Income_taxes_Details_2

Income taxes (Details 2) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Operating loss carryforwards	'
Net operating loss carryforwards	$702.40
2027	'
Operating loss carryforwards	'
Net operating loss carryforwards	50.3
2028	'
Operating loss carryforwards	'
Net operating loss carryforwards	101.6
2029	'
Operating loss carryforwards	'
Net operating loss carryforwards	82.5
2030	'
Operating loss carryforwards	'
Net operating loss carryforwards	25.8
2031	'
Operating loss carryforwards	'
Net operating loss carryforwards	57.3
2032	'
Operating loss carryforwards	'
Net operating loss carryforwards	85.6
2033	'
Operating loss carryforwards	'
Net operating loss carryforwards	$299.30

Equity_compensation_plans_Deta

Equity compensation plans (Details) (Long-term incentive plan, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Units	'	'	'
Outstanding at the beginning of the period (in shares)	492,535	485,781	600,981
Granted (in shares)	597,031	233,752	216,110
Additional shares from dividends (in shares)	64,576	38,667	36,204
Forfeitures (in shares)	-184,458	-28,932	-103,991
Vested and redeemed (in shares)	-202,696	-236,733	-263,523
Outstanding at the end of the period (in shares)	766,988	492,535	485,781
Grant Date Weighted Average Fair Value per Unit	'	'	'
Outstanding at the beginning of the period (in dollars per share)	$13.90	$11.49	$10.28
Granted (in dollars per share)	$4.91	$14.67	$14.02
Additional shares from dividends (in dollars per share)	$8.74	$13.43	$11.04
Forfeitures (in dollars per share)	$8.17	$13.63	$11.55
Vested and redeemed (in dollars per share)	$13.48	$10.18	$9.40
Outstanding at the end of the period (in dollars per share)	$7.86	$13.90	$11.49
Fair value of outstanding notional units	$4.80	$6.30	'
Compensation expense related to LTIP	2.2	2.5	3.2
Cash payments made for vested notional units	$0.90	$1.10	$1.50
Assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'	'	'
Weighted average risk free rate of return, minimum (as a percent)	0.10%	0.10%	'
Weighted average risk free rate of return, maximum (as a percent)	0.50%	0.30%	'
Dividend yield (as a percent)	10.80%	10.10%	'
Expected volatility Atlantic Power (as a percent)	50.40%	22.50%	'
Weighted average remaining measurement period	'1 year 9 months 25 days	'1 year 4 months 20 days	'
Minimum	'	'	'
Assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'	'	'
Expected volatility of peer companies (as a percent)	11.40%	11.90%	'
Maximum	'	'	'
Assumptions for calculation of simulated total shareholder return under the Monte Carlo model	'	'	'
Expected volatility of peer companies (as a percent)	56.40%	97.10%	'

Defined_benefit_plan_Details

Defined benefit plan (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Defined benefit plan	'	'
Expected contribution to pension plans	$1.40	'
Net annual periodic pension cost	'	'
Service cost benefits earned	0.9	0.8
Interest cost on benefit obligation	0.7	0.6
Expected return on plan assets	-0.8	-0.6
Gain amortization	0.1	'
Net period benefit cost	0.9	0.8
Change in benefit obligation	'	'
Benefit obligation at beginning of the year	-16.8	-12.7
Service cost	-0.9	-0.8
Interest cost	-0.7	-0.6
Actuarial (gain) loss	1.4	-2.3
Employee contributions	-0.1	-0.1
Benefit paid	0.1	'
Foreign currency translation adjustment	1	-0.3
Benefit obligation at end of year	-16	-16.8
Change in plan assets	'	'
Fair value of plan assets at beginning of the year	12	10.5
Actual return on plan assets	1.8	0.8
Employer contributions	2.3	0.4
Employee contributions	0.1	0.1
Benefit paid	-0.1	'
Foreign currency translation adjustment	-1	0.2
Fair value of plan assets at end of year	15.1	12
Funded status at end of year - excess of obligation over assets	-0.9	-4.8
Amount recognized in the balance sheet	'	'
Non-current liabilities	0.9	4.8
Amounts recognized in accumulated OCI	'	'
Unrecognized loss	0.3	1.3
Amortization of net loss for the pension plan from accumulated OCI to net periodic cost over the next fiscal year	0	'
Balances of significant components of the pension plan	'	'
Projected benefit obligation	16	16.8
Accumulated benefit obligation	12.4	13.1
Fair value of plan assets	$15.10	$12

Defined_benefit_plan_Details_2

Defined benefit plan (Details 2) (CAD)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Weighted-Average Assumptions used to calculate benefit obligations	'	'
Discount rate (as a percent)	5.00%	4.00%
Rate of compensation increase (as a percent)	4.00%	4.00%
Weighted-Average Assumptions used to calculate benefit expense	'	'
Discount rate (as a percent)	4.00%	4.00%
Rate of return on plan assets (as a percent)	6.00%	5.50%
Percentage of plan assets	100.00%	100.00%
Period over which corporate AA rated yield curve extrapolated to derive CIA/Natcan curve	'10 years	'
Maturity period of corporate bonds rated AA	'10 years	'
Expected future benefit payments	'	'
2014	0.1	'
2015	0.2	'
2016	0.3	'
2017	0.3	'
2018	0.4	'
2019-2023	3.4	'
Minimum	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Rate of compensation increase (as a percent)	3.00%	3.00%
Maximum	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Rate of compensation increase (as a percent)	4.00%	4.00%
Canadian equity	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Percentage of plan assets	30.00%	30.00%
U.S. equity	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Percentage of plan assets	17.00%	13.00%
International equity	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Percentage of plan assets	15.00%	14.00%
Canadian fixed income	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Percentage of plan assets	38.00%	40.00%
International fixed income	'	'
Weighted-Average Assumptions used to calculate benefit expense	'	'
Percentage of plan assets	'	3.00%

Common_shares_Details

Common shares (Details)	0 Months Ended
In Millions, except Share data, unless otherwise specified	Jul. 05, 2012	Jul. 05, 2012	Nov. 05, 2011	Oct. 19, 2011	Oct. 19, 2011
	USD ($)	CAD		USD ($)	CAD
Common shares	'	'	'	'	'
Shares issued in connection with acquisition	'	'	31,500,215	'	'
Issuance of common shares	5,567,177	5,567,177	'	12,650,000	12,650,000
Issuance of common shares pursuant to the exercise of underwriters' over-allotment option in public offering	'	'	'	1,650,000	1,650,000
Price of common shares issued (in dollars per share)	$12.76	13.1	'	$13	13.26
Proceed from issuance of common stock public offering net of underwriting discounts and costs	$68.50	'	'	$155.40	'

Preferred_shares_issued_by_a_s1

Preferred shares issued by a subsidiary company (Details) (Epsilon)	12 Months Ended			12 Months Ended					12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2009	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2007	Dec. 31, 2007	Dec. 31, 2007	Dec. 31, 2013	Dec. 31, 2012
	Series 2 Shares	Series 2 Shares	Series 2 Shares	Series 3 Shares	Series 1 Shares	Series 1 Shares	Series 1 Shares	Series 1 Shares	Series 1 Shares and Series 2 Shares	Series 1 Shares and Series 2 Shares
	CAD	CAD	December 31, 2014 and every five years thereafter		CAD	CAD	Beginning on June 30, 2012	After June 30, 2016	USD ($)	USD ($)
			CAD				CAD	CAD
Preferred shares issued by subsidiary company	'	'	'	'	'	'	'	'	'	'
Number of preferred shares issued	'	4	'	'	'	5	'	'	'	'
Dividend rate on preferred shares (as a percent)	'	7.00%	'	'	'	4.85%	'	'	'	'
Issue price of preferred shares (in Canadian dollars per share)	'	25	'	'	'	25	'	'	'	'
Dividend per share per annum (in Canadian dollars per share)	1.75	'	'	'	1.2125	'	'	'	'	'
Redemption price after specified date and thereafter (in Canadian dollars per share)	'	'	25	'	'	'	26	25	'	'
Decline in redemption price per year (in Canadian dollars per share)	'	'	'	'	'	0.25	'	'	'	'
Initial period for declaration of dividend	'5 years	'	'	'	'	'	'	'	'	'
Period for declaration of dividend at reset rate	'5 years	'	'	'	'	'	'	'	'	'
Reference rate for dividend	'Five-year Government of Canada bond yield	'	'	'90-day Government of Canada treasury bill rate	'	'	'	'	'	'
Percentage points added to the reference rate	4.18%	'	'	4.18%	'	'	'	'	'	'
Frequency for redemption after December 31, 2014	'5 years	'	'	'	'	'	'	'	'	'
Dividend paid	'	'	'	'	'	'	'	'	$12.60	$13

Basic_and_diluted_earnings_los2

Basic and diluted earnings (loss) per share (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Numerator:	'	'	'	'	'	'	'	'	'	'	'
Loss from continuing operations attributable to Atlantic Power Corporation	$8.20	($40.20)	$7.20	$7.20	($19.70)	($23.50)	($20.80)	($50.20)	($26.80)	($126.70)	($72.70)
Income (loss) from discontinued operations, net of tax	'	'	'	'	'	'	'	'	-6.2	13.9	34.3
Net Income (Loss) Available to Common Stockholders, Basic	$4.90	($41.30)	($3)	$6.40	($58)	($7.40)	($5.10)	($42.30)	($33)	($112.80)	($38.40)
Denominator:	'	'	'	'	'	'	'	'	'	'	'
Weighted average basic shares outstanding	120.1	120	119.9	119.5	119.4	119	113.7	113.6	119.9	116.4	77.5
Dilutive potential shares:	'	'	'	'	'	'	'	'	'	'	'
Convertible debentures (in shares)	'	'	'	'	'	'	'	'	27.7	17.4	14
LTIP notional units (in shares)	'	'	'	'	'	'	'	'	0.7	0.5	0.4
Potentially dilutive shares	'	'	'	'	'	'	'	'	148.3	134.3	91.9
Diluted income (loss) per share from discontinued operations (in dollars per share)	$0.04	($0.34)	$0.02	$0.05	($0.20)	($0.22)	($0.20)	($0.47)	($0.23)	($1.09)	($0.94)
Diluted earnings (loss) per share from discontinued operations (in dollars per share)	'	'	($0.05)	'	($0.30)	$0.16	$0.16	$0.10	($0.05)	$0.12	$0.44
Net income (loss) attributable to Atlantic Power Corporation (in dollars per share)	$0.04	($0.34)	($0.03)	$0.05	($0.50)	($0.06)	($0.04)	($0.37)	($0.28)	($0.97)	($0.50)

Assets_held_for_sale_Details

Assets held for sale (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assets held for sale	'	'	'	'	'	'	'	'	'	'	'
Revenue	'	'	'	'	'	'	'	'	$71.60	$216.70	$191
Income (loss) from discontinued operations	'	'	'	'	'	'	'	'	-5.4	15.7	37.1
Income tax expense	'	'	'	'	'	'	'	'	0.8	1.8	2.8
Income (loss) from discontinued operations, net of tax	-0.2	-0.4	-6	0.4	-34.8	19	18.7	11	-6.2	13.9	34.3
Basic and diluted earnings (loss) per share income (loss) from discontinued operations	'	'	'	'	'	'	'	'	($0.05)	$0.12	$0.44
Current assets:	'	'	'	'	'	'	'	'	'	'	'
Cash and cash equivalents	'	'	'	'	6.5	'	'	'	'	6.5	'
Restricted cash	'	'	'	'	12.6	'	'	'	'	12.6	'
Accounts receivable	'	'	'	'	21.9	'	'	'	'	21.9	'
Other current assets	'	'	'	'	6.3	'	'	'	'	6.3	'
Total current assets	'	'	'	'	47.3	'	'	'	'	47.3	'
Non-current assets:	'	'	'	'	'	'	'	'	'	'	'
Property, plant, and equipment	'	'	'	'	111.9	'	'	'	'	111.9	'
Transmission system rights	'	'	'	'	172.4	'	'	'	'	172.4	'
Goodwill	'	'	'	'	8.9	'	'	'	'	8.9	'
Other assets	'	'	'	'	10.9	'	'	'	'	10.9	'
Assets held for sale	'	'	'	'	351.4	'	'	'	'	351.4	'
Current liabilities:	'	'	'	'	'	'	'	'	'	'	'
Accounts payable and other accrued liabilities	'	'	'	'	16.5	'	'	'	'	16.5	'
Current portion of long-term debt	'	'	'	'	14.3	'	'	'	'	14.3	'
Current portion of derivative instruments liability	'	'	'	'	20	'	'	'	'	20	'
Other liabilities	'	'	'	'	0.5	'	'	'	'	0.5	'
Total current liabilities	'	'	'	'	51.3	'	'	'	'	51.3	'
Long-term liabilities	'	'	'	'	'	'	'	'	'	'	'
Long-term debt	'	'	'	'	137.7	'	'	'	'	137.7	'
Liabilities held for sale	'	'	'	'	$189	'	'	'	'	$189	'
Rollcast	'	'	'	'	'	'	'	'	'	'	'
Assets held for sale	'	'	'	'	'	'	'	'	'	'	'
Ownership interest sold (as a percent)	60.00%	'	'	'	'	'	'	'	60.00%	'	'

Segment_and_geographic_informa2

Segment and geographic information (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
									item
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Number of Reportable Segments	'	'	'	'	'	'	'	'	4	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	$130.70	$141.80	$139.10	$140.10	$114	$106.30	$101.40	$118.70	$551.70	$440.40	$93.90
Segment assets	3,395	'	'	'	4,002.70	'	'	'	3,395	4,002.70	3,248.40
Goodwill	296.3	'	'	'	334.7	'	'	'	296.3	334.7	343.6
Capital expenditures	'	'	'	'	'	'	'	'	26.2	468.1	115.1
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	270.5	227.6	86.8
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	-50.3	56.6	17.2
Depreciation and amortization	'	'	'	'	'	'	'	'	209.8	164.9	55.5
Interest, net	'	'	'	'	'	'	'	'	38.5	24	15.2
Other project (income) expense	'	'	'	'	'	'	'	'	8.2	11.5	2.5
Project income (loss)	7.2	4.8	20.8	31.5	-5.8	19.7	-6.9	-36.4	64.3	-29.4	-3.6
Administration	'	'	'	'	'	'	'	'	35.2	28.3	37.7
Interest, net	'	'	'	'	'	'	'	'	104.1	89.8	26
Foreign exchange gain (loss)	'	'	'	'	'	'	'	'	27.4	-0.5	-13.8
Other income, net	'	'	'	'	'	'	'	'	-10.5	-5.7	-0.1
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	-37.1	-142.3	-81
Income tax benefit	'	'	'	'	'	'	'	'	-19.5	-28.1	-11.1
Loss from continuing operations	'	'	'	'	'	'	'	'	-17.6	-114.2	-69.9
Income (loss) from discontinued operations	-0.2	-0.4	-6	0.4	-34.8	19	18.7	11	-6.2	13.9	34.3
Net income (loss)	'	'	'	'	'	'	'	'	-23.8	-100.3	-35.6
East	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Goodwill	107.8	'	'	'	138.6	'	'	'	107.8	138.6	138.6
West	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Goodwill	188.5	'	'	'	192.6	'	'	'	188.5	192.6	201.5
Operating Segments | East	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	299.1	267.5	66
Segment assets	1,395.20	'	'	'	1,600.20	'	'	'	1,395.20	1,600.20	1,683.90
Goodwill	107.8	'	'	'	138.6	'	'	'	107.8	138.6	138.6
Capital expenditures	'	'	'	'	'	'	'	'	13.8	25.5	115
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	150.7	145.7	66.8
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	-24.4	56.6	17.5
Depreciation and amortization	'	'	'	'	'	'	'	'	93.7	87.5	37.3
Interest, net	'	'	'	'	'	'	'	'	20.7	18.5	11.5
Other project (income) expense	'	'	'	'	'	'	'	'	34.9	1.2	2.6
Project income (loss)	'	'	'	'	'	'	'	'	25.8	-18.1	-2.1
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	25.8	-18.1	-2.1
Loss from continuing operations	'	'	'	'	'	'	'	'	25.8	-18.1	-2.1
Income (loss) from discontinued operations	'	'	'	'	'	'	'	'	-1.1	13.6	31.8
Net income (loss)	'	'	'	'	'	'	'	'	24.7	-4.5	29.7
Operating Segments | West	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	182.3	169.6	26.6
Segment assets	1,001.50	'	'	'	1,305.30	'	'	'	1,001.50	1,305.30	1,392.10
Goodwill	188.5	'	'	'	192.6	'	'	'	188.5	192.6	201.5
Capital expenditures	'	'	'	'	'	'	'	'	1.1	0.2	0.1
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	78.8	82.1	16.4
Depreciation and amortization	'	'	'	'	'	'	'	'	68.3	71.4	15.2
Interest, net	'	'	'	'	'	'	'	'	0.4	0.4	0.8
Other project (income) expense	'	'	'	'	'	'	'	'	-26.3	3	-0.3
Project income (loss)	'	'	'	'	'	'	'	'	36.4	7.3	0.7
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	36.4	7.3	0.7
Loss from continuing operations	'	'	'	'	'	'	'	'	36.4	7.3	0.7
Income (loss) from discontinued operations	'	'	'	'	'	'	'	'	1.3	2.9	4.4
Net income (loss)	'	'	'	'	'	'	'	'	37.7	10.2	5.1
Operating Segments | Wind	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	70.8	1.9	'
Segment assets	853.9	'	'	'	956.3	'	'	'	853.9	956.3	48.6
Capital expenditures	'	'	'	'	'	'	'	'	11.1	441.6	'
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	59.6	10.9	4.3
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	-25.9	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	47.3	5.9	3
Interest, net	'	'	'	'	'	'	'	'	19.5	5.1	2.9
Other project (income) expense	'	'	'	'	'	'	'	'	0.1	7.3	'
Project income (loss)	'	'	'	'	'	'	'	'	18.6	-7.4	-1.6
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	18.6	-7.4	-1.6
Loss from continuing operations	'	'	'	'	'	'	'	'	18.6	-7.4	-1.6
Net income (loss)	'	'	'	'	'	'	'	'	18.6	-7.4	-1.6
Operating Segments | Northeast	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	227.2	'	'
Segment assets	1,136.10	'	'	'	'	'	'	'	1,136.10	'	'
Goodwill	104.5	'	'	'	'	'	'	'	104.5	'	'
Capital expenditures	'	'	'	'	'	'	'	'	4.3	'	'
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	133.1	'	'
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	-19.4	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	79.4	'	'
Interest, net	'	'	'	'	'	'	'	'	17	'	'
Other project (income) expense	'	'	'	'	'	'	'	'	34.5	'	'
Project income (loss)	'	'	'	'	'	'	'	'	21.6	'	'
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	21.6	'	'
Loss from continuing operations	'	'	'	'	'	'	'	'	21.6	'	'
Net income (loss)	'	'	'	'	'	'	'	'	21.6	'	'
Operating Segments | Southeast	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	22	'	'
Segment assets	170.7	'	'	'	'	'	'	'	170.7	'	'
Capital expenditures	'	'	'	'	'	'	'	'	9.5	'	'
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	11.3	'	'
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	-5	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	10.7	'	'
Interest, net	'	'	'	'	'	'	'	'	3.6	'	'
Other project (income) expense	'	'	'	'	'	'	'	'	0.1	'	'
Project income (loss)	'	'	'	'	'	'	'	'	1.9	'	'
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	1.9	'	'
Loss from continuing operations	'	'	'	'	'	'	'	'	1.9	'	'
Income (loss) from discontinued operations	'	'	'	'	'	'	'	'	-1.1	'	'
Net income (loss)	'	'	'	'	'	'	'	'	0.8	'	'
Operating Segments | Northwest	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	88.6	'	'
Segment assets	1,050.80	'	'	'	'	'	'	'	1,050.80	'	'
Goodwill	138.3	'	'	'	'	'	'	'	138.3	'	'
Capital expenditures	'	'	'	'	'	'	'	'	4.7	'	'
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	67.2	'	'
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	-25.9	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	60.3	'	'
Interest, net	'	'	'	'	'	'	'	'	18.9	'	'
Other project (income) expense	'	'	'	'	'	'	'	'	0.1	'	'
Project income (loss)	'	'	'	'	'	'	'	'	13.8	'	'
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	13.8	'	'
Loss from continuing operations	'	'	'	'	'	'	'	'	13.8	'	'
Net income (loss)	'	'	'	'	'	'	'	'	13.8	'	'
Operating Segments | Southwest	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	214.4	'	'
Segment assets	893	'	'	'	'	'	'	'	893	'	'
Goodwill	53.5	'	'	'	'	'	'	'	53.5	'	'
Capital expenditures	'	'	'	'	'	'	'	'	7.5	'	'
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	77.5	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	58.9	'	'
Interest, net	'	'	'	'	'	'	'	'	1.1	'	'
Other project (income) expense	'	'	'	'	'	'	'	'	-26	'	'
Project income (loss)	'	'	'	'	'	'	'	'	43.5	'	'
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	43.5	'	'
Loss from continuing operations	'	'	'	'	'	'	'	'	43.5	'	'
Income (loss) from discontinued operations	'	'	'	'	'	'	'	'	1.3	'	'
Net income (loss)	'	'	'	'	'	'	'	'	44.8	'	'
Un-allocated Corporate	'	'	'	'	'	'	'	'	'	'	'
Segment and geographic information	'	'	'	'	'	'	'	'	'	'	'
Project revenues	'	'	'	'	'	'	'	'	-0.5	1.4	1.3
Segment assets	144.4	'	'	'	140.9	'	'	'	144.4	140.9	123.8
Goodwill	'	'	'	'	3.5	'	'	'	'	3.5	3.5
Capital expenditures	'	'	'	'	'	'	'	'	0.2	0.8	'
Project Adjusted EBITDA	'	'	'	'	'	'	'	'	18.6	-11.1	-0.7
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	'	'	-0.3
Depreciation and amortization	'	'	'	'	'	'	'	'	0.5	0.1	'
Interest, net	'	'	'	'	'	'	'	'	2.1	'	'
Other project (income) expense	'	'	'	'	'	'	'	'	-0.5	'	0.2
Project income (loss)	'	'	'	'	'	'	'	'	-16.5	-11.2	-0.6
Administration	'	'	'	'	'	'	'	'	35.2	28.3	37.7
Interest, net	'	'	'	'	'	'	'	'	104.1	89.8	26
Foreign exchange gain (loss)	'	'	'	'	'	'	'	'	-27.4	0.5	13.8
Other income, net	'	'	'	'	'	'	'	'	-10.5	-5.7	-0.1
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	-117.9	-124.1	-78
Income tax benefit	'	'	'	'	'	'	'	'	-19.5	-28.1	-11.1
Loss from continuing operations	'	'	'	'	'	'	'	'	-98.4	-96	-66.9
Income (loss) from discontinued operations	'	'	'	'	'	'	'	'	-6.4	-2.6	-1.9
Net income (loss)	'	'	'	'	'	'	'	'	($104.80)	($98.60)	($68.80)

Segment_and_geographic_informa3

Segment and geographic information (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue and Assets	'	'	'	'	'	'	'	'	'	'	'
Revenue	$130.70	$141.80	$139.10	$140.10	$114	$106.30	$101.40	$118.70	$551.70	$440.40	$93.90
Property, plant, and equipment, net	1,813.40	'	'	'	2,055.50	'	'	'	1,813.40	2,055.50	'
United States	'	'	'	'	'	'	'	'	'	'	'
Revenue and Assets	'	'	'	'	'	'	'	'	'	'	'
Revenue	'	'	'	'	'	'	'	'	343.4	227.2	58.1
Property, plant, and equipment, net	1,330.50	'	'	'	1,504.80	'	'	'	1,330.50	1,504.80	'
Canada	'	'	'	'	'	'	'	'	'	'	'
Revenue and Assets	'	'	'	'	'	'	'	'	'	'	'
Revenue	'	'	'	'	'	'	'	'	208.3	213.2	35.8
Property, plant, and equipment, net	$482.90	'	'	'	$550.70	'	'	'	$482.90	$550.70	'

Segment_and_geographic_informa4

Segment and geographic information (Details 3)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Ontario Electricity Financial Corp (OEFC)	'	'
Consolidated revenue concentration	'	'
Percentage of consolidated revenue	27.70%	34.70%
San Diego Gas & Electric	'	'
Consolidated revenue concentration	'	'
Percentage of consolidated revenue	14.40%	9.80%
BC Hydro	'	'
Consolidated revenue concentration	'	'
Percentage of consolidated revenue	10.10%	13.60%
Revenues, net | Consolidated revenue | Ontario Electricity Financial Corp (OEFC)	'	'
Consolidated revenue concentration	'	'
Percentage of consolidated revenue	27.70%	34.70%
Revenues, net | Consolidated revenue | BC Hydro	'	'
Consolidated revenue concentration	'	'
Percentage of consolidated revenue	10.10%	13.60%

Related_party_transactions_Det

Related party transactions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
	Idaho Wind	Idaho Wind	ArcLight	ArcLight	ArcLight	ArcLight
						item
Related party transactions	'	'	'	'	'	'
Number of private equity funds	'	'	'	'	'	2
Aggregate amount payable on termination of contract	'	'	'	'	'	$15
Payment due on termination date for termination of agreement	'	'	'	'	'	6
Additional payment due on first anniversary of termination date	'	'	'	'	5	'
Additional payment due on second anniversary of termination date	'	'	'	3	'	'
Additional payment due on third anniversary of termination date	'	'	1	'	'	'
Loan to Idaho Wind	'	22.8	'	'	'	'
Interest income from loan given to Idaho Wind	$1.60	'	'	'	'	'

Commitments_and_contingencies_1

Commitments and contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and contingencies.	'	'	'
Lease expense under operating leases	$1	$2	$1
Future minimum lease commitments under operating leases	'	'	'
2014	1.6	'	'
2015	1.8	'	'
2016	1.7	'	'
2017	1.6	'	'
2018	1.5	'	'
Thereafter	12.9	'	'
Future minimum lease commitments	21.1	'	'
Estimated commitments under Long-Term Service Agreements	'	'	'
2014	3.5	'	'
2015	5	'	'
2016	5	'	'
2017	5	'	'
2018	5	'	'
Thereafter	24.4	'	'
Total	47.9	'	'
Fuel Supply and Transportation Commitments	'	'	'
2014	83	'	'
2015	80	'	'
2016	73	'	'
2017	23.4	'	'
2018	23.6	'	'
Thereafter	70.4	'	'
Total	$353.40	'	'

Commitments_and_contingencies_2

Commitments and contingencies (Details 2) (USD $)	0 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 09, 2013	7-May-13	Dec. 31, 2013	Aug. 19, 2013	Oct. 04, 2013
	item	item	item	item
Commitments and contingencies	'	'	'	'	'
Number of District Court actions alleged from July 23, 2010 to March 4, 2013	'	'	3	'	'
Number of District Court actions alleged from August 8, 2012 to February 28, 2013	'	'	2	'	'
Number of actions were succeeded by specific action with an amended claim	'	'	3	'	'
Number of actions by which specific Ontario actions were succeeded	'	'	1	'	'
Accrual related to proposed adjustments pertaining to the classification of U.S. real property	'	'	0	'	'
Shareholder class action lawsuits	'	'	'	'	'
Commitments and contingencies	'	'	'	'	'
Number of purported securities fraud class action complaints filed	'	'	5	'	'
Number of action complaints filed ordered to consolidate	'	'	'	5	'
Number of plaintiff applicants directed to file supplemental submissions	2	'	'	'	'
Number of notices of actions relating to Canadian securities class action claims	'	'	3	'	'
Estimate damages claimed for statutory misrepresentation	'	'	'	'	$197.40
Number of District Court actions in which discoveries are stayed	'	'	5	'	'
Number of District Court actions alleged in specific period	'	'	5	'	'
Number of investors filed motion	'	6	'	'	'

Unaudited_selected_quarterly_f2

Unaudited selected quarterly financial data (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unaudited selected quarterly financial data	'	'	'	'	'	'	'	'	'	'	'
Project revenue	$130.70	$141.80	$139.10	$140.10	$114	$106.30	$101.40	$118.70	$551.70	$440.40	$93.90
Project (loss) income	7.2	4.8	20.8	31.5	-5.8	19.7	-6.9	-36.4	64.3	-29.4	-3.6
Income (loss) from continuing operations	8.2	-40.2	7.2	7.2	-19.7	-23.5	-20.8	-50.2	-26.8	-126.7	-72.7
Income (loss) from discontinued operations	-0.2	-0.4	-6	0.4	-34.8	19	18.7	11	-6.2	13.9	34.3
Net income (loss) attributable to Atlantic Power Corporation	$4.90	($41.30)	($3)	$6.40	($58)	($7.40)	($5.10)	($42.30)	($33)	($112.80)	($38.40)
Income (loss) per share from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	$0.04	($0.34)	$0.02	$0.05	($0.20)	($0.22)	($0.20)	($0.47)	($0.23)	($1.09)	'
Loss per share from discontinued operations (in dollars per share)	'	'	($0.05)	'	($0.30)	$0.16	$0.16	$0.10	($0.05)	$0.12	'
Net loss attributable to Atlantic Power Corporation (in dollars per share)	$0.04	($0.34)	($0.03)	$0.05	($0.50)	($0.06)	($0.04)	($0.37)	($0.28)	($0.97)	'
Weighted average number of common shares outstanding - basic	120.1	120	119.9	119.5	119.4	119	113.7	113.6	119.9	116.4	77.5
Diluted income (loss) per share from continuing operations attributable to Atlantic Power Corporation (in dollars per share)	$0.04	($0.34)	$0.02	$0.05	($0.20)	($0.22)	($0.20)	($0.47)	($0.23)	($1.09)	($0.94)
Diluted (loss) earnings per share from discontinued operations (in dollars per share)	'	'	($0.05)	'	($0.30)	$0.16	$0.16	$0.10	($0.05)	$0.12	$0.44
Net income (loss) attributable to Atlantic Power Corporation (in dollars per share)	$0.04	($0.34)	($0.03)	$0.05	($0.50)	($0.06)	($0.04)	($0.37)	($0.28)	($0.97)	($0.50)
Weighted average number of common shares outstanding - diluted	120.1	120	119.9	119.9	119.4	119	113.7	113.6	119.9	116.4	77.5

Consolidating_financial_inform2

Consolidating financial information (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Nov. 05, 2011	Dec. 31, 2013
In Millions, unless otherwise specified		Senior Notes	Senior Notes	Senior Notes	Senior Notes
					Guarantor Subsidiaries
Long-term debt	'	'	'	'	'
Total debt	$1,471	$460	$460	$460	'
Percentage of ownership in subsidiary (as a percent)	'	'	'	'	100.00%

Consolidating_financial_inform3

Consolidating financial information (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
Current assets:	'	'	'	'
Cash and cash equivalents	$158.60	$60.20	$60.70	$45.50
Restricted cash	114.2	28.6	'	'
Accounts receivable	64.3	58.5	'	'
Prepayments, supplies, and other	36.3	63	'	'
Assets held for sale	'	351.4	'	'
Total current assets	373.4	561.7	'	'
Property, plant, and equipment, net	1,813.40	2,055.50	'	'
Equity investments in unconsolidated affiliates	394.3	428.7	'	'
Other intangible assets, net	451.5	524.9	'	'
Goodwill	296.3	334.7	343.6	'
Other assets	66.1	97.2	'	'
Total assets	3,395	4,002.70	3,248.40	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	90.5	110.5	'	'
Revolving credit facility	'	67	'	'
Current portion of long-term debt	216.2	121.2	'	'
Current portion convertible debentures	42.1	'	'	'
Dividends payable	6.8	11.5	'	'
Liabilities held for sale	'	189	'	'
Other current liabilities	33.8	47.8	'	'
Total current liabilities	389.4	535.5	'	'
Long-term debt	1,254.80	1,459.10	'	'
Convertible debentures	363.1	424.2	189.6	'
Other non-current liabilities	291.7	397.5	'	'
Equity	'	'	'	'
Common Stock	1,286.10	1,285.50	'	'
Preferred shares issued by a subsidiary company	221.3	221.3	'	'
Accumulated other comprehensive income	-22.4	9.4	'	'
Retained (deficit) earnings	-655.4	-565.2	'	'
Total Atlantic Power Corporation shareholders' equity	829.6	951	'	'
Noncontrolling interest	266.4	235.4	'	'
Total equity	1,096	1,186.40	1,115.80	433.4
Total liabilities and equity	3,395	4,002.70	'	'
Eliminations	'	'	'	'
Current assets:	'	'	'	'
Accounts receivable	-138.8	-117	'	'
Prepayments, supplies, and other	'	-1	'	'
Total current assets	-138.8	-118	'	'
Property, plant, and equipment, net	-1.3	-1.2	'	'
Equity investments in unconsolidated affiliates	-4,204.50	-5,692.60	'	'
Other assets	-845.7	-842.6	'	'
Total assets	-5,190.30	-6,654.40	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	-138.8	-117	'	'
Other current liabilities	'	-1	'	'
Total current liabilities	-138.8	-118	'	'
Other non-current liabilities	-845.7	-842.6	'	'
Equity	'	'	'	'
Common Stock	-4,417.50	-5,318	'	'
Retained (deficit) earnings	211.7	-375.8	'	'
Total Atlantic Power Corporation shareholders' equity	-4,205.80	-5,693.80	'	'
Total equity	-4,205.80	-5,693.80	'	'
Total liabilities and equity	-5,190.30	-6,654.40	'	'
Guarantor Subsidiaries | Reportable legal entities	'	'	'	'
Current assets:	'	'	'	'
Cash and cash equivalents	151	43.2	58.5	33
Restricted cash	114.2	28.6	'	'
Accounts receivable	181.2	138.8	'	'
Prepayments, supplies, and other	33.3	53.4	'	'
Assets held for sale	'	351.4	'	'
Total current assets	479.7	615.4	'	'
Property, plant, and equipment, net	1,642.60	1,883.60	'	'
Equity investments in unconsolidated affiliates	3,655	5,109.30	'	'
Other intangible assets, net	304.7	367.1	'	'
Goodwill	238.1	276.5	'	'
Other assets	476.7	499.7	'	'
Total assets	6,796.80	8,751.60	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	141.9	169.8	'	'
Revolving credit facility	'	47	'	'
Current portion of long-term debt	26.2	121.2	'	'
Dividends payable	6.8	'	'	'
Liabilities held for sale	'	189	'	'
Other current liabilities	30	37.3	'	'
Total current liabilities	204.9	564.3	'	'
Long-term debt	794.8	809.1	'	'
Other non-current liabilities	1,128.30	1,230.80	'	'
Equity	'	'	'	'
Common Stock	4,226.20	5,103.80	'	'
Preferred shares issued by a subsidiary company	221.3	221.3	'	'
Accumulated other comprehensive income	-22.4	9.4	'	'
Retained (deficit) earnings	-22.7	577.5	'	'
Total Atlantic Power Corporation shareholders' equity	4,402.40	5,912	'	'
Noncontrolling interest	266.4	235.4	'	'
Total equity	4,668.80	6,147.40	'	'
Total liabilities and equity	6,796.80	8,751.60	'	'
Curtis Palmer | Reportable legal entities	'	'	'	'
Current assets:	'	'	'	'
Accounts receivable	17.6	35.8	'	'
Prepayments, supplies, and other	1.3	1.3	'	'
Total current assets	18.9	37.1	'	'
Property, plant, and equipment, net	172.1	173.1	'	'
Other intangible assets, net	146.8	157.8	'	'
Goodwill	58.2	58.2	'	'
Total assets	396	426.2	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	6.1	13.7	'	'
Current portion of long-term debt	190	'	'	'
Total current liabilities	196.1	13.7	'	'
Long-term debt	'	190	'	'
Other non-current liabilities	8.6	8.3	'	'
Equity	'	'	'	'
Common Stock	191.3	214.2	'	'
Total Atlantic Power Corporation shareholders' equity	191.3	214.2	'	'
Total equity	191.3	214.2	'	'
Total liabilities and equity	396	426.2	'	'
APC | Reportable legal entities	'	'	'	'
Current assets:	'	'	'	'
Cash and cash equivalents	7.6	17	2.2	12.5
Accounts receivable	4.3	0.9	'	'
Prepayments, supplies, and other	1.7	9.3	'	'
Total current assets	13.6	27.2	'	'
Equity investments in unconsolidated affiliates	943.8	1,012	'	'
Other assets	435.1	440.1	'	'
Total assets	1,392.50	1,479.30	'	'
Current liabilities:	'	'	'	'
Accounts payable and accrued liabilities	81.3	44	'	'
Revolving credit facility	'	20	'	'
Current portion convertible debentures	42.1	'	'	'
Other current liabilities	3.8	11.5	'	'
Total current liabilities	127.2	75.5	'	'
Long-term debt	460	460	'	'
Convertible debentures	363.1	424.2	'	'
Other non-current liabilities	0.5	1	'	'
Equity	'	'	'	'
Common Stock	1,286.10	1,285.50	'	'
Retained (deficit) earnings	-844.4	-766.9	'	'
Total Atlantic Power Corporation shareholders' equity	441.7	518.6	'	'
Total equity	441.7	518.6	'	'
Total liabilities and equity	$1,392.50	$1,479.30	'	'

Consolidating_financial_inform4

Consolidating financial information (Details 3) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Project revenue:	'	'	'	'	'	'	'	'	'	'	'
Energy sales	'	'	'	'	'	'	'	'	$304.20	$217	$43.60
Energy capacity revenue	'	'	'	'	'	'	'	'	168.8	154.9	34
Other	'	'	'	'	'	'	'	'	78.7	68.5	16.3
Total project revenue	130.7	141.8	139.1	140.1	114	106.3	101.4	118.7	551.7	440.4	93.9
Project expenses:	'	'	'	'	'	'	'	'	'	'	'
Fuel	'	'	'	'	'	'	'	'	198.7	169.1	37.5
Project operations and maintenance	'	'	'	'	'	'	'	'	152.4	122.8	20.9
Project development expenses	'	'	'	'	'	'	'	'	7.2	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	167.1	118	23.6
Total project expenses	'	'	'	'	'	'	'	'	525.4	409.9	82
Project other income (expense):	'	'	'	'	'	'	'	'	'	'	'
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	49.5	-59.3	-14.6
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	26.9	15.2	6.4
Gain on sale of equity investments	'	'	'	'	'	'	'	'	30.4	0.6	'
Interest expense, net	'	'	'	'	'	'	'	'	-34.4	-16.4	-7.3
Other income, net	'	'	'	'	'	'	'	'	0.5	'	'
Total project other income (expense)	'	'	'	'	'	'	'	'	38	-59.9	-15.5
Project income (loss)	7.2	4.8	20.8	31.5	-5.8	19.7	-6.9	-36.4	64.3	-29.4	-3.6
Administrative and other expenses (income):	'	'	'	'	'	'	'	'	'	'	'
Administration expense	'	'	'	'	'	'	'	'	35.2	28.3	37.7
Interest, net	'	'	'	'	'	'	'	'	104.1	89.8	26
Foreign exchange loss	'	'	'	'	'	'	'	'	-27.4	0.5	13.8
Other income	'	'	'	'	'	'	'	'	-10.5	-5.7	-0.1
Total administrative and other expenses (income)	'	'	'	'	'	'	'	'	101.4	112.9	77.4
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	-37.1	-142.3	-81
Income tax (benefit) expense	'	'	'	'	'	'	'	'	-19.5	-28.1	-11.1
Loss from continuing operations	'	'	'	'	'	'	'	'	-17.6	-114.2	-69.9
Net Income (loss) from discontinued operations, net of tax	-0.2	-0.4	-6	0.4	-34.8	19	18.7	11	-6.2	13.9	34.3
Net loss	'	'	'	'	'	'	'	'	-23.8	-100.3	-35.6
Net loss attributable to noncontrolling interests	'	'	'	'	'	'	'	'	-3.4	-0.6	-0.5
Net income attributable to preferred shares dividends of a subsidiary company	'	'	'	'	'	'	'	'	12.6	13.1	3.3
Net Income (Loss) Available to Common Stockholders, Basic	4.9	-41.3	-3	6.4	-58	-7.4	-5.1	-42.3	-33	-112.8	-38.4
Eliminations	'	'	'	'	'	'	'	'	'	'	'
Project revenue:	'	'	'	'	'	'	'	'	'	'	'
Other	'	'	'	'	'	'	'	'	-0.5	-0.6	-0.4
Total project revenue	'	'	'	'	'	'	'	'	-0.5	-0.6	-0.4
Project expenses:	'	'	'	'	'	'	'	'	'	'	'
Project operations and maintenance	'	'	'	'	'	'	'	'	-0.5	-0.4	-0.3
Total project expenses	'	'	'	'	'	'	'	'	-0.5	-0.4	-0.3
Project other income (expense):	'	'	'	'	'	'	'	'	'	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	'	'	0.4
Interest expense, net	'	'	'	'	'	'	'	'	'	'	-1.6
Total project other income (expense)	'	'	'	'	'	'	'	'	'	'	-1.2
Project income (loss)	'	'	'	'	'	'	'	'	'	-0.2	-1.3
Administrative and other expenses (income):	'	'	'	'	'	'	'	'	'	'	'
Interest, net	'	'	'	'	'	'	'	'	'	0.2	'
Total administrative and other expenses (income)	'	'	'	'	'	'	'	'	'	0.2	'
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	'	-0.4	-1.3
Loss from continuing operations	'	'	'	'	'	'	'	'	'	-0.4	-1.3
Net loss	'	'	'	'	'	'	'	'	'	-0.4	-1.3
Net Income (Loss) Available to Common Stockholders, Basic	'	'	'	'	'	'	'	'	'	-0.4	-1.3
Guarantor Subsidiaries | Reportable legal entities	'	'	'	'	'	'	'	'	'	'	'
Project revenue:	'	'	'	'	'	'	'	'	'	'	'
Energy sales	'	'	'	'	'	'	'	'	268.4	182.8	34.6
Energy capacity revenue	'	'	'	'	'	'	'	'	168.8	154.9	34
Other	'	'	'	'	'	'	'	'	79.2	69.1	16.7
Total project revenue	'	'	'	'	'	'	'	'	516.4	406.8	85.3
Project expenses:	'	'	'	'	'	'	'	'	'	'	'
Fuel	'	'	'	'	'	'	'	'	198.7	169.1	37.5
Project operations and maintenance	'	'	'	'	'	'	'	'	148.2	117.3	19.4
Project development expenses	'	'	'	'	'	'	'	'	7.2	'	'
Depreciation and amortization	'	'	'	'	'	'	'	'	151.7	102.7	21
Total project expenses	'	'	'	'	'	'	'	'	505.8	389.1	77.9
Project other income (expense):	'	'	'	'	'	'	'	'	'	'	'
Change in fair value of derivative instruments	'	'	'	'	'	'	'	'	49.5	-59.3	-14.6
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	26.9	15.8	6
Gain on sale of equity investments	'	'	'	'	'	'	'	'	30.4	'	'
Interest expense, net	'	'	'	'	'	'	'	'	-23.3	-5.2	-3.9
Other income, net	'	'	'	'	'	'	'	'	-34.7	'	'
Total project other income (expense)	'	'	'	'	'	'	'	'	48.8	-48.7	-12.5
Project income (loss)	'	'	'	'	'	'	'	'	59.4	-31	-5.1
Administrative and other expenses (income):	'	'	'	'	'	'	'	'	'	'	'
Administration expense	'	'	'	'	'	'	'	'	21.1	17.6	12.2
Interest, net	'	'	'	'	'	'	'	'	75.8	79.6	67.7
Foreign exchange loss	'	'	'	'	'	'	'	'	-9.4	1.1	4
Other income	'	'	'	'	'	'	'	'	-5.8	-6	-0.1
Total administrative and other expenses (income)	'	'	'	'	'	'	'	'	81.7	92.3	83.8
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	-22.3	-123.3	-88.9
Income tax (benefit) expense	'	'	'	'	'	'	'	'	-19.5	-28.1	-11.3
Loss from continuing operations	'	'	'	'	'	'	'	'	-2.8	-95.2	-77.6
Net Income (loss) from discontinued operations, net of tax	'	'	'	'	'	'	'	'	-6.2	13.9	34.3
Net loss	'	'	'	'	'	'	'	'	-9	-81.3	-43.3
Net loss attributable to noncontrolling interests	'	'	'	'	'	'	'	'	-3.4	-0.6	-0.5
Net income attributable to preferred shares dividends of a subsidiary company	'	'	'	'	'	'	'	'	12.6	13.1	3.3
Net Income (Loss) Available to Common Stockholders, Basic	'	'	'	'	'	'	'	'	-18.2	-93.8	-46.1
Curtis Palmer | Reportable legal entities	'	'	'	'	'	'	'	'	'	'	'
Project revenue:	'	'	'	'	'	'	'	'	'	'	'
Energy sales	'	'	'	'	'	'	'	'	35.8	34.2	9
Total project revenue	'	'	'	'	'	'	'	'	35.8	34.2	9
Project expenses:	'	'	'	'	'	'	'	'	'	'	'
Project operations and maintenance	'	'	'	'	'	'	'	'	3.8	6.1	0.9
Depreciation and amortization	'	'	'	'	'	'	'	'	15.4	15.3	2.6
Total project expenses	'	'	'	'	'	'	'	'	19.2	21.4	3.5
Project other income (expense):	'	'	'	'	'	'	'	'	'	'	'
Interest expense, net	'	'	'	'	'	'	'	'	-11.1	-11.2	-1.9
Total project other income (expense)	'	'	'	'	'	'	'	'	-11.1	-11.2	-1.9
Project income (loss)	'	'	'	'	'	'	'	'	5.5	1.6	3.6
Administrative and other expenses (income):	'	'	'	'	'	'	'	'	'	'	'
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	5.5	1.6	3.6
Loss from continuing operations	'	'	'	'	'	'	'	'	5.5	1.6	3.6
Net loss	'	'	'	'	'	'	'	'	5.5	1.6	3.6
Net Income (Loss) Available to Common Stockholders, Basic	'	'	'	'	'	'	'	'	5.5	1.6	3.6
APC | Reportable legal entities	'	'	'	'	'	'	'	'	'	'	'
Project expenses:	'	'	'	'	'	'	'	'	'	'	'
Project operations and maintenance	'	'	'	'	'	'	'	'	0.9	-0.2	0.9
Total project expenses	'	'	'	'	'	'	'	'	0.9	-0.2	0.9
Project other income (expense):	'	'	'	'	'	'	'	'	'	'	'
Interest expense, net	'	'	'	'	'	'	'	'	'	'	0.1
Other income, net	'	'	'	'	'	'	'	'	0.3	'	'
Total project other income (expense)	'	'	'	'	'	'	'	'	0.3	'	0.1
Project income (loss)	'	'	'	'	'	'	'	'	-0.6	0.2	-0.8
Administrative and other expenses (income):	'	'	'	'	'	'	'	'	'	'	'
Administration expense	'	'	'	'	'	'	'	'	14.1	10.7	25.5
Interest, net	'	'	'	'	'	'	'	'	28.3	10	-41.7
Foreign exchange loss	'	'	'	'	'	'	'	'	-18	-0.6	9.8
Other income	'	'	'	'	'	'	'	'	-4.7	0.3	'
Total administrative and other expenses (income)	'	'	'	'	'	'	'	'	19.7	20.4	-6.4
Loss from continuing operations before income taxes	'	'	'	'	'	'	'	'	-30.3	-20.2	5.6
Income tax (benefit) expense	'	'	'	'	'	'	'	'	'	'	0.2
Loss from continuing operations	'	'	'	'	'	'	'	'	-20.3	-20.2	5.4
Net loss	'	'	'	'	'	'	'	'	-20.3	-20.2	5.4
Net Income (Loss) Available to Common Stockholders, Basic	'	'	'	'	'	'	'	'	($20.30)	($20.20)	$5.40

Consolidating_financial_inform5

Consolidating financial information (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed consolidating statement of comprehensive income	'	'	'
Net loss	($23.80)	($100.30)	($35.60)
Other comprehensive income (loss):	'	'	'
Unrealized income (loss) on hedging activities	0.7	-0.9	-2.6
Net amount reclassified to earnings	0.9	0.9	1
Net unrealized gain (loss) on derivatives	1.6	'	-1.6
Defined benefit plan, net of tax	1.4	-1.3	-0.5
Foreign currency translation adjustments	-34.8	15.9	-3.3
Other comprehensive income (loss), net of tax	-31.8	14.6	-5.4
Comprehensive loss	-55.6	-85.7	-41
Less: Comprehensive income attributable to noncontrolling interests	9.2	12.5	2.8
Comprehensive loss attributable to Atlantic Power Corporation	-64.8	-98.2	-43.8
Eliminations	'	'	'
Condensed consolidating statement of comprehensive income	'	'	'
Net loss	'	-0.4	-1.3
Other comprehensive income (loss):	'	'	'
Comprehensive loss	'	-0.4	-1.3
Comprehensive loss attributable to Atlantic Power Corporation	'	-0.4	-1.3
Guarantor Subsidiaries | Reportable legal entities	'	'	'
Condensed consolidating statement of comprehensive income	'	'	'
Net loss	-9	-81.3	-43.3
Other comprehensive income (loss):	'	'	'
Unrealized income (loss) on hedging activities	0.7	-0.9	-2.6
Net amount reclassified to earnings	0.9	0.9	1
Net unrealized gain (loss) on derivatives	1.6	'	-1.6
Defined benefit plan, net of tax	1.4	-1.3	-0.5
Foreign currency translation adjustments	-34.8	15.9	-3.3
Other comprehensive income (loss), net of tax	-31.8	14.6	-5.4
Comprehensive loss	-40.8	-66.7	-48.7
Less: Comprehensive income attributable to noncontrolling interests	9.2	12.5	2.8
Comprehensive loss attributable to Atlantic Power Corporation	-50	-79.2	-51.5
Curtis Palmer | Reportable legal entities	'	'	'
Condensed consolidating statement of comprehensive income	'	'	'
Net loss	5.5	1.6	3.6
Other comprehensive income (loss):	'	'	'
Comprehensive loss	-14.2	1.6	3.6
Comprehensive loss attributable to Atlantic Power Corporation	-14.2	1.6	3.6
APC | Reportable legal entities	'	'	'
Condensed consolidating statement of comprehensive income	'	'	'
Net loss	-20.3	-20.2	5.4
Other comprehensive income (loss):	'	'	'
Comprehensive loss	-0.6	-20.2	5.4
Comprehensive loss attributable to Atlantic Power Corporation	($0.60)	($20.20)	$5.40

Consolidating_financial_inform6

Consolidating financial information (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net cash (used in) provided by operating activities:	$152.40	$167.10	$55.90
Cash flows provided by (used in) investing activities:	'	'	'
Cash paid for acquisitions and investments, net of cash acquired	'	-80.5	-591.6
Proceeds from treasury grants	103.2	'	'
Proceeds for sale of assets	182.6	'	'
Short-term loan to Idaho Wind	'	'	22.8
Proceeds from sale of assets and equity investments, net	182.6	27.9	8.5
Change in restricted cash	-93.7	-11.6	-5.7
Biomass development costs	-0.2	-0.5	-0.9
Construction in progress	-38.3	-456.2	-113.1
Purchase of property, plant and equipment	-6.5	-2.9	-2
Cash provided by (used in) investing activities	147.1	-523.8	-682
Cash flows (used in) provided by financing activities:	'	'	'
Proceeds from issuance of long-term debt	'	'	22.8
Proceeds from issuance of convertible debentures	'	230.6	'
Offering costs related to tax equity	-1	'	'
Proceeds from issuance of equity, net of offering costs	-1	66.3	155.4
Repayment of project-level debt	-118.8	-284.8	-21.5
Deferred financing costs	-2.8	-31.2	-26.4
Proceeds from project-level debt	20.8	291.9	100.8
Payments for revolving credit facilities	-67	-60.8	'
Proceeds from revolving credit facility borrowings	'	69.8	58
Equity investment from noncontrolling interest	44.6	225	'
Dividends paid	-83.4	-144.1	-85
Cash (used in) provided by financing activities	-207.6	362.7	641.3
Net (decrease) increase in cash and cash equivalents	91.9	6	15.2
Less cash at discontinued operations	'	-6.5	'
Cash and cash equivalents at beginning of period	60.2	60.7	45.5
Cash and cash equivalents at end of period	158.6	60.2	60.7
Guarantor Subsidiaries | Reportable legal entities	'	'	'
Cash flows from operating activities:	'	'	'
Net cash (used in) provided by operating activities:	61.7	-9.9	21
Cash flows provided by (used in) investing activities:	'	'	'
Cash paid for acquisitions and investments, net of cash acquired	'	206.5	12.1
Proceeds from treasury grants	103.2	'	'
Proceeds for sale of assets	182.6	'	'
Cash (paid) received for equity investments	11	'	'
Short-term loan to Idaho Wind	'	'	21.5
Proceeds from sale of assets and equity investments, net	'	27.9	8.5
Change in restricted cash	-93.7	-11.6	-5.7
Biomass development costs	-0.2	-0.5	-0.9
Construction in progress	-38.3	-456.2	-113.1
Purchase of property, plant and equipment	-3.5	-1.8	-2
Cash provided by (used in) investing activities	161.1	-235.7	-79.6
Cash flows (used in) provided by financing activities:	'	'	'
Offering costs related to tax equity	-1	'	'
Proceeds from issuance of equity, net of offering costs	'	-1.4	'
Repayment of project-level debt	-118.8	-284.8	-21.5
Deferred financing costs	'	-19.7	'
Proceeds from project-level debt	20.8	291.9	100.8
Payments for revolving credit facilities	-47	-30.8	'
Proceeds from revolving credit facility borrowings	'	69.8	8
Equity investment from noncontrolling interest	42.7	225	'
Dividends paid	-18.3	-13.1	-3.2
Cash (used in) provided by financing activities	-121.6	236.9	84.1
Net (decrease) increase in cash and cash equivalents	101.2	-8.7	25.5
Less cash at discontinued operations	'	-6.5	'
Cash and cash equivalents at beginning of period	43.2	58.5	33
Cash and cash equivalents at end of period	151	43.2	58.5
Curtis Palmer | Reportable legal entities	'	'	'
Cash flows from operating activities:	'	'	'
Net cash (used in) provided by operating activities:	3	1.1	'
Cash flows provided by (used in) investing activities:	'	'	'
Purchase of property, plant and equipment	-3	-1.1	'
Cash provided by (used in) investing activities	-3	-1.1	'
APC | Reportable legal entities	'	'	'
Cash flows from operating activities:	'	'	'
Net cash (used in) provided by operating activities:	87.7	175.9	34.9
Cash flows provided by (used in) investing activities:	'	'	'
Cash paid for acquisitions and investments, net of cash acquired	'	-287	-603.7
Cash (paid) received for equity investments	-11	'	'
Short-term loan to Idaho Wind	'	'	1.3
Cash provided by (used in) investing activities	-11	-287	-602.4
Cash flows (used in) provided by financing activities:	'	'	'
Proceeds from issuance of long-term debt	'	'	460
Proceeds from issuance of convertible debentures	'	230.6	'
Proceeds from issuance of equity, net of offering costs	'	67.7	155.4
Deferred financing costs	-2.8	-11.5	-26.4
Payments for revolving credit facilities	-20	-30	'
Proceeds from revolving credit facility borrowings	'	'	50
Equity investment from noncontrolling interest	1.9	'	'
Dividends paid	-65.1	-131	-81.8
Cash (used in) provided by financing activities	-86	125.8	557.2
Net (decrease) increase in cash and cash equivalents	-9.3	14.7	-10.3
Cash and cash equivalents at beginning of period	17	2.2	12.5
Cash and cash equivalents at end of period	$7.60	$17	$2.20

SCHEDULE_IIVALUATION_AND_QUALI1

SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS (Details) (Income tax valuation allowance, deducted from deferred tax assets:, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income tax valuation allowance, deducted from deferred tax assets:	'	'	'
Movement in valuation and qualifying accounts	'	'	'
Balance at Beginning of Period	$116	$89	$79.40
Charged to Costs and Expenses	12.1	20.2	9.4
Charged to Other Accounts	'	6.8	0.2
Balance at End of Period	$128.10	$116	$89