Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2015shares | |
Document Documentand Entity Information [Abstract] | |
Document Type | 40-F |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2015 |
Document Fiscal Year Focus | 2,015 |
Document Fiscal Period Focus | FY |
Trading Symbol | AQUNF |
Entity Registrant Name | ALGONQUIN POWER & UTILITIES CORP. |
Entity Central Index Key | 1,174,169 |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Common Stock, Shares Outstanding | 255,869,419 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | CAD 124,353 | CAD 9,273 |
Accounts receivable, net (note 4) | 186,681 | 188,573 |
Natural gas in storage (note 1(h)) | 28,502 | 31,550 |
Regulatory assets (note 7) | 32,213 | 61,645 |
Prepaid expenses | 18,409 | 10,431 |
Derivative instruments (note 24) | 15,039 | 10,688 |
Other current assets | 18,537 | 15,359 |
Assets, current, total | 423,734 | 327,519 |
Property, plant and equipment, net (note 5) | 3,873,684 | 3,278,422 |
Intangible assets, net (note 6) | 77,963 | 54,011 |
Goodwill (note 6) | 110,493 | 92,328 |
Regulatory assets (note 7) | 213,102 | 185,627 |
Derivative instruments (note 24) | 73,322 | 31,782 |
Total long-term investments | 174,802 | 43,279 |
Deferred income taxes (note 19) | 18,109 | 64,275 |
Other assets (note 12) | 26,516 | 25,605 |
Assets | 4,991,725 | 4,102,848 |
Current liabilities: | ||
Accounts payable | 50,428 | 68,540 |
Accrued liabilities | 193,320 | 199,374 |
Dividends payable (note 16) | 41,802 | 25,395 |
Regulatory liabilities (note 7) | 44,167 | 20,590 |
Long-term debt (note 9) | 8,945 | 9,130 |
Other long-term liabilities and deferred credits (note 13) | 36,621 | 49,303 |
Other liabilities | 16,593 | 10,234 |
Liabilities, current, total | 391,876 | 382,566 |
Long-term debt (note 9) | 1,477,850 | 1,262,589 |
Regulatory liabilities (note 7) | 131,180 | 101,166 |
Deferred income taxes (note 19) | 175,799 | 134,460 |
Derivative instruments (note 24) | 106,628 | 40,088 |
Pension and other post-employment benefits (note 10) | 150,094 | 138,602 |
Other long-term liabilities (note 13) | 223,135 | 177,235 |
Preferred shares, Series C (note 11) | 17,548 | 17,608 |
Liabilities, noncurrent, total | 2,282,234 | 1,871,748 |
Redeemable non-controlling interest (note 3(e)) | 25,751 | 12,146 |
Equity: | ||
Preferred shares (note 14(b)) | 213,805 | 213,805 |
Common shares (note 14(a)) | 1,808,894 | 1,633,262 |
Subscription receipts (note 14(a)(ii)) | 110,503 | 110,503 |
Additional paid-in capital | 38,241 | 33,068 |
Deficit | (523,116) | (505,305) |
Accumulated other comprehensive income (note 15) | 286,737 | 34,213 |
Total Equity attributable to shareholders of Algonquin Power & Utilities Corp. | 1,935,064 | 1,519,546 |
Non-controlling interests | 356,800 | 316,842 |
Total Equity | CAD 2,291,864 | CAD 1,836,388 |
Commitments and contingencies (note 22) | ||
Liabilities and equity, total | CAD 4,991,725 | CAD 4,102,848 |
Consolidated Statements of Oper
Consolidated Statements of Operations - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue | ||
Regulated electricity distribution | CAD 224,110 | CAD 204,721 |
Regulated gas distribution | 464,767 | 446,025 |
Regulated water reclamation and distribution | 78,467 | 66,419 |
Non-regulated energy sales | 222,581 | 202,300 |
Other revenue | 37,930 | 22,149 |
Total revenue | 1,027,855 | 941,614 |
Expenses | ||
Operating expenses | 278,561 | 234,038 |
Regulated electricity purchased | 131,647 | 120,506 |
Regulated gas purchased | 217,236 | 261,116 |
Non-regulated energy purchased | 27,990 | 39,264 |
Administrative expenses | 40,675 | 34,692 |
Depreciation and amortization | 149,806 | 114,047 |
Gain on foreign exchange | (2,631) | (1,112) |
Costs and Expenses, Total | 843,284 | 802,551 |
Operating income from continuing operations | 184,571 | 139,063 |
Interest expense | 65,993 | 62,418 |
Interest, dividend, equity and other income | (9,095) | (7,758) |
Other gains | (5,110) | 0 |
Acquisition-related costs | 1,832 | 2,552 |
Write-down of long-lived assets and loss on disposal | 2,890 | 8,027 |
Loss (gain) on derivative financial instruments | (2,188) | 1,375 |
Nonoperating Income (Expense) | 54,322 | 66,614 |
Earnings (loss) before income taxes | 130,249 | 72,449 |
Income tax expense (note 19) | ||
Current | 7,310 | 3,674 |
Deferred | 36,403 | 13,133 |
Income tax expense | 43,713 | 16,807 |
Earnings from continuing operations | 86,536 | 55,642 |
Loss from discontinued operations, net of tax | (1,032) | (2,127) |
Net earnings | 85,504 | 53,515 |
Net loss attributable to non-controlling interests (note 18) | (31,976) | (22,186) |
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp. | 117,480 | 75,701 |
Series A and D Preferred shares dividend (note 16) | 10,400 | 9,503 |
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp. | CAD 107,080 | CAD 66,198 |
Basic net earnings per share from continuing operations (cad per share) | CAD 0.43 | CAD 0.32 |
Basic net earnings per share (cad per share) | 0.42 | 0.31 |
Diluted net earnings per share from continuing operations (cad per share) | 0.42 | 0.32 |
Diluted net earnings per share (cad per share) | CAD 0.42 | CAD 0.31 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Comprehensive Income [Abstract] | ||
Net earnings | CAD 85,504 | CAD 53,515 |
Other comprehensive income: | ||
Foreign currency translation adjustment, net of tax recovery of $nil and $1,049, respectively (notes 1(v), 24(b)(iii) and 24(c)) | 289,035 | 104,183 |
Change in fair value of cash flow hedges’, net of tax expense of $12,010 and $6,589, respectively (note 24(b)(ii)) | 16,165 | 2,799 |
Change in unrealized appreciation in value of available-for-sale investments | (73) | 1 |
Change in pension and other post-employment benefits, net of tax expense of $4,923 and tax recovery of $22,446, respectively (note 10) | 7,571 | (35,669) |
Other comprehensive income, net of tax | 312,698 | 71,314 |
Comprehensive income | 398,202 | 124,829 |
Comprehensive income attributable to the non-controlling interests | 28,198 | 7,077 |
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp. | CAD 370,004 | CAD 117,752 |
Consolidated Statements of Com5
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Comprehensive Income [Abstract] | ||
Foreign currency translation adjustment, tax expense (recovery) | CAD 0 | CAD (1,049) |
Change in fair value of cash flow hedges', tax expense | 12,010 | 6,589 |
Change in pension and other post-employment benefits, tax expense (recovery) | CAD 4,923 | CAD (22,446) |
Consolidated Statement of Equit
Consolidated Statement of Equity - CAD CAD in Thousands | Total | Common shares | Preferred shares | Subscription receipts | Additional paid-in capital | Accumulated deficit | Accumulated OCI | Non- controlling interests |
Beginning Balance at Dec. 31, 2013 | CAD 1,465,961 | CAD 1,351,264 | CAD 116,546 | CAD 0 | CAD 7,313 | CAD (488,406) | CAD (31,410) | CAD 510,654 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net earnings (loss) | 53,515 | 75,701 | (22,186) | |||||
Redeemable non-controlling interests not included in equity | (289) | (289) | ||||||
Other comprehensive income | 71,314 | 42,051 | 29,263 | |||||
Dividends declared and distributions to non-controlling interests | (79,943) | (75,205) | (4,738) | |||||
Dividends and issuance of shares under dividend reinvestment plan | 0 | 17,395 | (17,395) | |||||
Contributions received from non-controlling interests | 9,934 | 9,934 | ||||||
Shares issued pursuant to public offering, net of costs | 263,869 | 263,869 | ||||||
Issuance of common shares under employee share purchase plan | 734 | 734 | ||||||
Share-based compensation | 3,203 | 3,203 | ||||||
Issuance of subscription receipts | 110,503 | 110,503 | ||||||
Preferred shares, Series D | 97,259 | 97,259 | ||||||
Acquisition of non-controlling interest | (159,672) | 22,552 | 23,572 | (205,796) | ||||
Ending Balance at Dec. 31, 2014 | 1,836,388 | 1,633,262 | 213,805 | 110,503 | 33,068 | (505,305) | 34,213 | 316,842 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net earnings (loss) | 85,504 | 117,480 | (31,976) | |||||
Redeemable non-controlling interests not included in equity | 3,571 | 3,571 | ||||||
Other comprehensive income | 312,698 | 252,524 | 60,174 | |||||
Dividends declared and distributions to non-controlling interests | (108,555) | (105,929) | (2,626) | |||||
Dividends and issuance of shares under dividend reinvestment plan | 0 | 29,302 | (29,302) | |||||
Contributions received from non-controlling interests | 10,815 | 10,815 | ||||||
Shares issued pursuant to public offering, net of costs | 144,987 | 144,987 | ||||||
Issuance of common shares under employee share purchase plan | 1,001 | 1,343 | (282) | (60) | ||||
Share-based compensation | 5,455 | 5,455 | ||||||
Ending Balance at Dec. 31, 2015 | CAD 2,291,864 | CAD 1,808,894 | CAD 213,805 | CAD 110,503 | CAD 38,241 | CAD (523,116) | CAD 286,737 | CAD 356,800 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Activities | ||
Net earnings from continuing operations | CAD 86,536 | CAD 55,642 |
Adjustments and items not affecting cash: | ||
Depreciation and amortization | 151,627 | 115,399 |
Deferred taxes | 36,403 | 13,133 |
Unrealized loss (gain) on derivative financial instruments | (1,990) | 3,046 |
Share-based compensation expense | 5,455 | 3,203 |
Cost of equity funds used for construction purposes | (2,424) | (1,910) |
Pension and post-employment expense | (3,333) | (2,050) |
Write-down of long-lived assets and loss on disposal | 1,781 | 8,463 |
Write-down of long-lived assets | 220 | 0 |
Increase in deferred income | 550 | 0 |
Changes in non-cash operating items (note 23) | (11,149) | (1,790) |
Changes in non-cash operating items from discontinued operations | 0 | 1,262 |
Cash used in discontinued operations | (1,806) | (1,682) |
Net Cash Provided by (Used in) Operating Activities, Total | 261,870 | 192,716 |
Financing Activities | ||
Cash dividends on common shares | (79,121) | (57,848) |
Cash dividends on preferred shares | (10,400) | (9,503) |
Cash contributions from non-controlling interests | 15,222 | 11,845 |
Production-based cash contributions from non-controlling interest | 10,815 | 8,976 |
Cash distributions to non-controlling interests | (2,936) | (4,738) |
Issuance of common shares, net of costs | 144,694 | 261,452 |
Proceeds from subscription receipts | 0 | 110,503 |
Issuance of preferred shares, net of costs | 0 | 96,271 |
Acquisition of non-controlling interest | 0 | (127,121) |
Increase in long-term debt | 248,811 | 236,528 |
Decrease in long-term debt | (196,149) | (286,552) |
Increase in other long-term liabilities | 31,544 | 18,618 |
Decrease in other long-term liabilities | (6,182) | (3,091) |
Net Cash Provided by (Used in) Financing Activities, Total | 156,298 | 255,340 |
Investing Activities | ||
Increase (decrease) in other assets | 281 | (13,785) |
Distributions received in excess of equity income | 1,386 | 264 |
Receipt of principal on notes receivable | 29,273 | 280 |
Additions to property, plant and equipment | (204,195) | (432,373) |
Acquisitions of long-term investments | (138,560) | (25,432) |
Acquisitions of operating entities | (3,717) | (8,757) |
Proceeds from sale of long-lived assets | 5,516 | 26,535 |
Net Cash Provided by (Used in) Investing Activities, Total | (310,016) | (453,268) |
Effect of exchange rate differences on cash | 6,928 | 646 |
Increase (decrease) in cash and cash equivalents | 115,080 | (4,566) |
Cash and cash equivalents, beginning of year | 9,273 | 13,839 |
Cash and cash equivalents, end of year | 124,353 | 9,273 |
Supplemental disclosure of cash flow information: | ||
Cash paid during the year for interest expense | 69,610 | 57,098 |
Cash paid during the year for income taxes | 6,153 | 2,571 |
Non-cash financing and investing activities: | ||
Property, plant and equipment acquisitions in accruals | 44,834 | 25,568 |
Issuance of common shares under dividend reinvestment plan and share-based compensation plans | CAD 30,645 | CAD 18,129 |
Notes to the Consolidated Finan
Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Notes to the Consolidated Financial Statements | Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC is a diversified generation, transmission and distribution utility company. The distribution business group operates in the United States under the name of Liberty Utilities Co. (“ Distribution Group ”) and provides rate regulated water, electricity and natural gas utility services. The generation business group operates under the name Algonquin Power Co. (“ Generation Group ”) and owns or has interests in a portfolio of non-regulated North American based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission business group operates under the name Liberty Utilities (Pipeline & Transmission) (“ Transmission Group ”) and invests in rate regulated electric transmission and natural gas pipeline systems in the United States and Canada. |
Significant accounting policies
Significant accounting policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Significant accounting policies | Significant accounting policies (a) Basis of preparation The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission. (b) Basis of consolidation The accompanying consolidated financial statements of APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(l)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(q)). (c) Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets which meet the definition of a business as business combinations. The determination of whether the definition of a business has been met for a development stage project depends on the stage of development (permitting, customer contracting, financing, construction) and the significance of the development risk with respect to achieving commercial operation. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date. Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisitions costs. Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is not included in the rate-base on which regulated utilities are allowed to earn a return and is not amortized. During the fourth quarter of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. 1. Significant accounting policies (continued) (d) Accounting for rate regulated operations The regulated utility operating companies owned by the Company are subject to rate regulation generally overseen by the public utility commission of the states in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated utility operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”)ASC Topic 980, Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment. In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets (liabilities). The impact could be material to the Company’s reported financial condition and results of operations. The electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”) and National Association of Regulatory Utility Commissioners. (e) Cash and cash equivalents Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less. (f) Restricted cash Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements and requirements of ISO New England, Inc. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash as part of other assets (note 12) in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC. (g) Accounts receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers. (h) Natural gas in storage Natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders (note 7(c)) and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments. Accordingly, the recoverable value of gas in storage does not fall below the cost to the Company. (i) Supplies and consumables inventory Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or become obsolete. These items are stated at the lower of cost and replacement cost. Supplies and consumables inventory is included in other current assets. 1. Significant accounting policies (continued) (j) Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority authorized and has committed to the funding of the project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate-regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory asset when it is determined that recovery of such costs through regulated revenue of the completed project is probable. The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under capital leases are initially recorded at cost determined as the present value of minimum lease payments. AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest, dividend, equity and other income on the consolidated statements of operations. 2015 2014 Interest capitalized on non-regulated property $ 1,189 $ 3,584 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,657 1,577 Allowance for equity funds 2,425 1,910 Total $ 5,271 $ 7,071 Improvements that increase or prolong the service life or capacity of an asset are capitalized. Cost incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Investment tax credits and government grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 13(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Investment tax credits and government grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2015 2014 2015 2014 Generation Group 3 - 60 3 - 60 32 35 Distribution Group 5 - 100 5 - 100 42 40 Equipment 5 - 50 5 - 50 14 14 Effective January 1, 2015, the Company changed the depreciation method from the straight-line method to the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component. This change in the depreciation method results from having better information on the consumption of the benefits of certain individual components that are directly related to production and separately identified in the records of the Company. The change is being recognized prospectively.The impact of the change on the operating results for 2015 was a reduction of depreciation expense of $3,418 . The impact on basic and diluted net earnings per share for 2015 was an increase of $0.01 . The change is not expected to materially affect net earnings or net earnings per share on an annual basis. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Distribution Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. (k) Impairment of long-lived assets APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Assets held and used: Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. Assets held for sale: Recoverability of assets held for sale is measured by comparing the carrying amount of an asset to its fair value less cost to sell. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value less estimated costs to sell. 1. Significant accounting policies (continued) (l) Variable interest entities The Company performs analysis to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8(a) and (b)). The Company has equity and notes receivable interests in two power generating facilities. APUC has determined that both entities are considered a VIE mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As APUC has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entity, the Company is considered the primary beneficiary. Total net book value of generating assets and long-term debt of these facilities amounts to $104,243 (2014 - $112,344 ) and $62,138 (2014 - $59,449 ), respectively. The debt only has recourse over the generating assets. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $18,651 (2014 - $11,218 ), operating expenses and amortization of $5,645 (2014 - $3,418 ) and interest expense of $4,407 (2014 - $3,820 ). (m) Long-term investments and notes receivable Investments in which APUC has significant influence but not control are accounted using the equity method. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. APUC records its share in the income or loss of its investees in interest, dividend, equity and other income in the consolidated statements of operations. Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company acquired these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned. If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. (n) Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, and other post-employment benefit (“OPEB”) plans for its various employee groups in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans and OPEB plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and are recognized as part of administrative expenses in the consolidated statements of operations. 1. Significant accounting policies (continued) (o) Asset retirement obligations The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Actual expenditures incurred are charged against the obligation. (p) Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. Equity classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expense in the consolidated statements of operations and contributed surplus in equity. Contributed surplus is reduced as the awards are exercised, and the amount initially recorded in contributed surplus is credited to common shares. (q) Non-controlling interests Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests. If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company. Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units”) which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV method uses a balance sheet approach, which measures the allocation of income or loss of the Class A partnership units in each period by calculating the change in the amount of distribution the partners would contractually be entitled to based on a hypothetical liquidation of the book value carrying amounts of the entity at the beginning of a reporting period compared to the end of that period (note 18). Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification. 1. Significant accounting policies (continued) (r) Recognition of revenue Revenue derived from non-regulated energy generation sales, which are mostly under long-term power purchase contracts, is recorded at the time electrical energy is delivered. Revenue related to utility electricity and natural gas sales and distribution are recorded when the electricity or natural gas is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Revenue for the Company’s Calpeco Electric System, Peach State Gas System and New England Gas System is subject to a revenue decoupling mechanism approved by their respective regulator which require to charge approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7(e)). Water reclamation and distribution revenues are recorded when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue is recorded net of sales taxes. During the year, the Company settled insurance claims for business interruption at some of its generation facilities under repairs and as a result recognized revenue of $581 (2014 - $1,227 ). (s) Foreign currency translation The Company’s reporting currency is the Canadian dollar. The Company’s U.S. operations are determined to have the U.S. dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. The financial statements of these operations are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment. (t) Income taxes Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Income tax credits are treated as a reduction to current income tax expense in the year the credit arises or future periods to the extent that realization of such benefit is more likely than not. 1. Significant accounting policies (continued) (t) Income taxes (continued) The organizational structure of APUC and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. (u) Financial instruments and derivatives Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts. Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument. The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities in the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk exposure, interest risk and price risk exposure associated with sales of generated electricity. For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized in OCI. The ineffective portion is immediately recognized in earnings. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings. Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings. The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption. 1. Significant accounting policies (continued) (v) Fair value measurements The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels: • Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabiliti |
Recently issued accounting pron
Recently issued accounting pronouncements | 12 Months Ended |
Dec. 31, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently issued accounting pronouncements | Recently issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued ASU 2015-17 Income Taxes (Topic 740) to simplify the presentation of deferred income taxes. This ASU requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this ASU. The Company retrospectively adopted this ASU in the fourth quarter of 2015. As a result, a deferred tax asset and a deferred tax liability of $7,210 and $ 3,702 , respectively, that were presented as current as of December 31, 2014 have been reclassified to non-current deferred tax asset and deferred tax liability on the consolidated balance sheets. The FASB issued ASU 2015-13 Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets. This ASU clarifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. The adoption of this ASU in the third quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-10, Technical Corrections and Improvements, to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification. The adoption of this ASU in the second quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-04, Compensation: Retirement Benefits (Subtopic 715), to provide a practical expedient that permits an entity with a fiscal year-end that does not coincide with a month-end and an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations to measure defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end or significant event. The Company adopted this ASU prospectively in the second quarter of 2015 and as a result, remeasured amendments to its pension plans, made during the second quarter, using the month-end closest to the amendments. The FASB issued ASU 2015-03, Interest: Imputation of Interest (Subtopic 835-30), to simplify presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected. Effective January 1, 2015, the Company applied this ASU retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt. In accordance with ASU 2015-15 Interest: Imputation of Interest (Subtopic 835-30), the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments as other assets. The FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This newly issued accounting standard raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Effective January 1, 2015, the Company adopted this ASU prospectively and as a result, its adoption had no impact on discontinued operations reported in prior periods. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged . The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard. The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations. |
Business acquisitions and devel
Business acquisitions and development projects | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Business acquisitions and development projects | Business acquisitions and development projects (a) Acquisition of Empire Subsequent to year-end, on February 9, 2016, the Company entered into an agreement and plan of merger pursuant to which, a subsidiary of Liberty Utilities Co. will merge with and into The Empire District Electric Company and its subsidiaries (“Empire”), and Empire will survive the merger and become a wholly owned indirect subsidiary of the Company. Empire is a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. Empire shareholders will receive U.S. $34.00 per common share in cash, which represents an aggregate purchase price of approximately $3,400,000 (U.S. $2,400,000 ), which includes the assumption of approximately $1,300,000 (U.S. $900,000 ) of debt. The closing of the acquisition, which is expected to occur in early 2017, is subject to customary closing conditions, including the approval of Empire’s common shareholders, and the receipt of certain state and federal regulatory and government approvals. On February 9, 2016, the Company obtained a $2,200,000 (U.S. $1,600,000 ) bridge financing commitment for the acquisition from a syndicate of banks (note 9). On March 1, 2016, the Company issued $1,000,000 aggregate principal amount of 5.0% convertible unsecured subordinated debentures represented by instalment receipts (the “Debentures” or the “Debenture Offering”) and received the first instalment of $333,000 . On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional Debentures and received the first instalment of $49,950 . The Debentures are expected to convert to common shares of the Company upon the closing of the acquisition of Empire (note 25). (b) Acquisition of Park Water System Subsequent to year-end, on January 8, 2016, the Company completed the acquisition of Western Water Holdings, LLC which is the parent company of Park Water Company (“Park Water System”), a regulated water distribution utility. Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and western Montana. The total purchase price for the Park Water System is U.S. $341,750 , including debt assumed of U.S. $91,750 and is subject to certain closing adjustments. All costs related to the acquisition have been expensed through the consolidated statements of operations. Due to the timing of the acquisition, the Company has not completed the fair value measurements of the assets acquired and liabilities assumed. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed. Mountain Water Company is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the City of Missoula will ultimately take possession of Mountain Water Company. The City’s right to take Mountain Water Company is currently on appeal before the Montana Supreme Court, which is set to hear the appeal on April 22, 2016. If the City of Missoula prevails on appeal and ultimately takes possession of Mountain Water Company, the compensation to be paid by the City of Missoula for such taking will be the value of the utility plus accrued interest and attorney’s fees as determined by the Montana court. (c) Commercial operation of Morse Wind Facility In 2015, the Company completed construction of a 23 MW wind generating facility located near Morse, Saskatchewan (“Morse Wind Facility”). Sale of power to the utility commenced in March 2015 at rates equivalent to those under the power purchase agreement. Commercial operation date as defined in the power purchase agreement occurred on April 22, 2015. The cost of the generating assets of $65,016 is recorded as property, plant and equipment on the consolidated balance sheets while $16,709 is recorded as intangible Assets, for a total investment of $81,725 . The weighted average useful life of the Morse Wind Facility is 35 years. 3. Business acquisitions and development projects (continued) (d) Acquisition of New Hampshire Gas On January 2, 2015, the Distribution Group completed the acquisition of New Hampshire Gas, a regulated propane gas distribution utility located in Keene, New Hampshire. The New Hampshire Gas System services approximately 1,200 propane gas distribution customers. Total purchase price for the New Hampshire Gas System is U.S. $3,161 . (e) Commercial operation of Bakersfield Solar I Facility In 2014, the Company completed construction a 20 MWac solar powered generating facility located in Kern County, California (“Bakersfield I Solar Facility”) which was placed in service on December 31, 2014. The Bakersfield I Solar Facility started selling power at the power purchase agreement price on May 15, 2015. The cost of these generating assets amounts to U.S.$ 57,160 and is recorded as property, plant and equipment on the consolidated balance sheets. The cost of the original development project is subject to certain adjustments which are expected to be finalized in 2016. The weighted average useful life of the Bakersfield Solar I Facility is 34 years. The Bakersfield I Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield I Partnership”). The Class A partnership units are owned by a third-party (the “Tax Equity Investor”) who funded a total of U.S. $22,438 to the project. With its partnership interest, the Tax Equity Investor will receive the majority of the tax attributes associated with the project. During a six-month period in year 2020, the Tax Investor has the right to withdraw from the Bakersfield I Solar Facility and require the Company to redeem its remaining interests for cash. As a result, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets. Redemption is not considered probable as of December 31, 2015. (f) Commercial operation of Saint-Damase Wind Facility In 2014, the Company completed construction of a 24 MW wind powered generating facility located near St. Damase, Quebec (“Saint-Damase Wind Facility”) which achieved commercial operation on December 2, 2014. The cost of these generating assets amounts to $64,155 and is recorded as property, plant and equipment on the consolidated balance sheets. The weighted average useful life of the Saint-Damase Wind Facility is 34 years. (g) Acquisition of White Hall Water System On May 30, 2014, the Distribution Group acquired the assets of the White Hall Water System, a regulated water distribution and wastewater treatment utility located in White Hall, Arkansas. The White Hall Water System serves approximately 1,900 water distribution and 2,400 wastewater treatment customers. Total purchase price for the White Hall Water System assets, adjusted for certain working capital and other closing adjustments, is approximately U.S. $4,499 . (h) Acquisition of non-controlling interest in U.S. wind farms On March 31, 2014 , the Company acquired the 40% interest in Wind Portfolio SponsorCo, LLC (“Wind Portfolio SponsorCo”) for approximately U.S. $115,000 . Wind Portfolio SponsorCo indirectly holds the interests in Sandy Ridge, Senate and Minonk Wind acquired in 2012. As a result of the transaction, the Generation Group now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units resulting in the elimination of the non-controlling interest in respect of the Class B partnership units of Wind Portfolio SponsorCo as follows: Elimination of non-controlling interest in Class B partnership units $ 205,796 Non-controlling interest portion of currency translation adjustment recorded to AOCI (21,029 ) Non-controlling interest portion of unrealized gain on cash flow hedges recorded to AOCI (2,543 ) Decrease in deferred income tax asset (32,551 ) Additional paid-in capital (22,552 ) Cash $ 127,121 3. Business acquisitions and development projects (continued) (i) Commercial operation of Cornwall Solar Facility In 2014, the Company completed the construction of a 10 MWac solar powered generating facility located near Cornwall, Ontario (“Cornwall Solar Facility”) which achieved commercial operation on March 27, 2014. The cost of these generating assets of $40,090 is recorded as property, plant and equipment while $7,243 is recorded as intangible assets, for a total investment of $47,333 . The weighted average useful life of the Cornwall Solar Facility is 33 years. (j) Acquisition of New England Gas System On December 20, 2013 , the Company acquired certain regulated natural gas distribution utility assets (the “New England Gas System”) located in the State of Massachusetts. Total purchase price for the New England Gas System, net of the debt assumed, is $67,010 (U.S.$ 62,745 ), including the purchase price adjustment of U.S. $3,108 finalized in 2014. In 2014, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed. The key retrospective adjustments to the assets and liabilities were an increase to the regulatory asset for pension of U.S. $2,701 , a decrease of property, plant and equipment of U.S. $1,190 , an increase of the environmental obligation of U.S. $2,467 and an increase of the pension obligation of U.S. $772 . (k) Acquisition of Shady Oaks Wind Facility Effective January 1, 2013 , the Company acquired the 109.5 MW Shady Oaks wind-powered generating facility (“Shady Oaks Wind Facility”). The purchase agreement provides for final purchase price adjustments based on working capital at the acquisition date, energy generated by the project and basis differences between the relevant node and hub prices which are expected to be finalized in 2016. Changes in measurement of the final purchase price adjustment subsequent to December 31, 2013, the end of the business combination measurement period, are recorded in current period operations. To that effect, no gain or loss was recognized in 2015 (2014 - U.S. $1,133 ). |
Accounts receivable
Accounts receivable | 12 Months Ended |
Dec. 31, 2015 | |
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract] | |
Accounts receivable | Accounts receivable Accounts receivable as of December 31, 2015 include unbilled revenue of $49,002 (2014 - $52,880 ) from the Company’s regulated utilities. Accounts receivable as of December 31, 2015 are presented net of allowance for doubtful accounts of $7,966 (2014 - $7,229 ). |
Property, plant and equipment
Property, plant and equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property, plant and equipment | Property, plant and equipment Property, plant and equipment consist of the following: 2015 Cost Accumulated depreciation Net book value Generation $ 2,138,748 $ 358,200 $ 1,780,548 Distribution 2,075,059 265,741 1,809,318 Land 23,258 — 23,258 Equipment and other 129,555 37,443 92,112 Construction in progress Generation 64,779 — 64,779 Distribution 103,669 — 103,669 $ 4,535,068 $ 661,384 $ 3,873,684 5. Property, plant and equipment (continued) 2014 Cost Accumulated Net book Generation $ 1,827,247 $ 270,746 $ 1,556,501 Distribution 1,555,289 147,726 1,407,563 Land 19,347 — 19,347 Equipment and other 119,367 29,526 89,841 Construction in progress Generation 82,840 — 82,840 Distribution 122,330 — 122,330 $ 3,726,420 $ 447,998 $ 3,278,422 Generation assets include cost of $158,514 ( 2014 - $155,629 ) and accumulated depreciation of $38,507 ( 2014 - $34,013 ) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $2,117 ( 2014 - $2,274 ). Investments tax credits, government grants and contributions received in aid of construction of $9,623 ( 2014 - $362 ) have been credited to the cost of the assets. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return. |
Intangible assets and goodwill
Intangible assets and goodwill | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible assets and goodwill | Intangible assets and goodwill Intangible assets consist of the following: 2015 Cost Accumulated amortization Net book value Power sales contracts $ 78,725 $ 40,244 $ 38,481 Customer relationships 37,083 10,371 26,712 Interconnection agreements 13,000 230 12,770 $ 128,808 $ 50,845 $ 77,963 2014 Cost Accumulated Net book Power sales contracts $ 64,605 $ 33,704 $ 30,901 Customer relationships 31,094 7,984 23,110 Interconnection agreements — — — — $ 95,699 $ 41,688 $ 54,011 Estimated amortization expense for intangible assets for the next year is $5,420 , $3,620 in year two, $3,250 in year three, $3,200 in year four and $3,160 in year five. 6. Intangible assets and goodwill (continued) Changes in goodwill are as follows: Distribution Group Balance, January 1, 2014 $ 84,647 Foreign exchange 7,681 Balance, December 31, 2014 $ 92,328 Business acquisitions 290 Foreign exchange 17,875 Balance, December 31, 2015 $ 110,493 |
Regulatory matters
Regulatory matters | 12 Months Ended |
Dec. 31, 2015 | |
Regulated Operations [Abstract] | |
Regulatory matters | Regulatory matters The Company’s regulated utility operating companies are subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these state authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate-setting process. At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. On February 18, 2016, the Georgia Public Service Commission approved a Final Order for the Peach State Gas System of a U.S. $2,725 revenue increase effective March 1, 2016. On February 10, 2016, the New England Gas System received a Final Order from the Massachusetts Department of Public Utilities approving an annual revenue increase of U.S. $7,800 effective March 1, 2016. On June 26, 2015, the EnergyNorth Gas System received a Final Order from the New Hampshire Public Utility Commission approving a settlement agreement allowing for a U.S. $12,400 revenue increase effective July 1, 2015. On March 12, 2015, the Pine Bluff Water System received a Final Order from the Arkansas Public Service Commission approving a revenue increase of U.S. $1,087 effective March 15, 2015. On February 11, 2015, the Midstates Gas System received a Final Order from the Illinois Commerce Commission approving a rate increase of U.S. $4,625 effective February 20, 2015. On March 17, 2014, the Granite State Electric System received a Final Order from the New Hampshire Public Utilities Commission approving a rate increase of U.S. $10,875 consisting of U.S. $9,760 in base rates and an additional U.S. $1,115 for incremental capital expended after the test year. In addition, the Order allows for a one time recovery of rate case expenses of U.S. $390 . The new rates were effective as of April 1, 2014 for services rendered on and after July 1, 2013. On April 18, 2014, the LPSCo Water System received a Final Order from the Arizona Corporation Commission approving a rate increase of U.S. $1,767 in connection with its rate application filed on February 28, 2013. The new rates became effective on May 1, 2014. In May 2014, the Peach State Gas System received a Final Order from the Georgia Public Service approving an annual revenue increase of U.S. $3,235 in connection with its annual GRAM filing on October 1, 2013. The new rates were effective as of June 1, 2014 for services rendered on and after February 1, 2014. On December 3, 2014, the Midstates Gas System received a Final Order from the Missouri Public Service Commission approving a rate increase of U.S. $4,868 effective January 2, 2015. On December 4, 2014, the Peach State Gas System received a Final Order from the Georgia Public Service approving an annual revenue increase of U.S. $3,680 in connection with its annual GRAM filing on October 1, 2014. The new rates are effective as of February 1, 2015. 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2015 2014 Regulatory assets Environmental remediation (a) $ 116,747 $ 102,735 Pension and post-employment benefits (b) 69,537 63,512 Commodity costs adjustment (c) 7,643 41,502 Rate case costs (d) 6,535 4,161 Rate adjustment mechanism (e) 14,804 6,207 Other 30,049 29,155 Total regulatory assets $ 245,315 $ 247,272 Less current regulatory assets (32,213 ) (61,645 ) Non-current regulatory assets $ 213,102 $ 185,627 Regulatory liabilities Cost of removal (f) $ 107,988 $ 78,013 Rate-base offset (g) 24,984 23,427 Commodity costs adjustment (c) 32,423 10,389 Other 9,952 9,927 Total regulatory liabilities $ 175,347 $ 121,756 Less current regulatory liabilities (44,167 ) (20,590 ) Non-current regulatory liabilities $ 131,180 $ 101,166 (a) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 13(b)) are recovered through rates over a period of 7 years and are subject to an annual cap. (b) Pension and post-employment benefits As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. An amount of $32,313 relates to a recent acquisition and was authorized for recognition as an asset by the regulator. Recovery is anticipated to be approved in a final rate order to be received on completion of the next general rate case. The balance is recovered through rates over the future services years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712 Compensation Non-retirement Post-employment Benefits and ASC 715 Compensation Retirement Benefits before the transfer to regulatory asset occurred. (c) Commodity costs adjustment The revenue of the electric and natural gas utilities includes a component which is designed to recover the cost of electricity or natural gas through rates charged to customers. Under deferred energy accounting, to the extent actual natural gas and purchased power costs differ from natural gas and purchased power costs recoverable through current rates, that difference is not recorded on the consolidated statements of operations but rather is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of natural gas or electricity in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. 7. Regulatory matters (continued) (d) Rate case costs The costs to file, prosecute and defend rate case applications are referred to as rate case costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Peach State Gas System and New England Gas Systems are subject to a revenue decoupling mechanism approved by their respective regulator which require charging approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but collected over a period not exceeding 24 months is accrued upon approval of the Final Order. (f) Cost of removal The regulatory liability for cost of removal represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire the utility plant. (g) Rate-base offset The regulators imposed a rate-base offset that would reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of ten years. As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company earns carrying charges on the regulatory balances related to commodity cost adjustment and rate case costs. |
Long-term investments
Long-term investments | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Long Term Investments And Notes Receivable [Abstract] | |
Long-term investments | Long-term investments Long-term investments consist of the following: 2015 2014 Equity-method investees 50% interest in Odell Wind Project Joint Venture (a) $ 42,287 $ 2,267 50% interest in Deerfield Wind Project Joint Venture (b) 2,240 — Interests in natural gas pipeline developments (c) 5,623 1,063 Other 2,323 3,268 $ 52,473 $ 6,598 Available-for-sale investment $ 2,946 $ 137 Notes receivable Development loans (d) $ 96,924 $ 17,582 Red Lily Senior loan Tranche 2, interest at 6.31% (e) 11,588 11,588 Red Lily Subordinated loan Tranche 1, interest at 12.5% (e) 6,565 6,565 Other 4,306 3,775 119,383 39,510 Total long-term investments 174,802 46,245 Less current portion — (2,966 ) Total long-term investments $ 174,802 $ 43,279 8. Long-term investments (continued) (a) Odell Wind Project Joint Venture On November 14, 2014, the Company acquired a 50% equity interest in Odell SponsorCo LLC (“Odell SponsorCo”), which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Project”) in the state of Minnesota. The total construction costs of the Odell Wind Project are estimated to be U.S. $322,766 . The two members each contributed U.S. $1,000 to the capital of Odell SponsorCo on acquisition and another U.S. $23,800 on October 6, 2015. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments, within 30 days of commencement of operations, which is expected in 2016. The interest capitalized during the year to the investment while the Odell Wind Project is under construction amounts to $4,415 (2014 - nil ). As of December 31, 2015, Odell SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Odell SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $190,840 as of December 31, 2015. (b) Deerfield Wind Project Joint Venture On October 19, 2015, the Company acquired a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan. The total construction costs of the Deerfield Wind Project are estimated to be U.S. $303,000 . Upon the acquisition of the Deerfield Wind Project by Deerfield SponsorCo, the two members each contributed U.S. $1,000 to the capital of Deerfield SponsorCo. Upon execution of third-party construction loan and tax equity documents expected in 2016, each party will contribute another U.S. $18,596 plus accrued interest at 7% to the capital of Deerfield SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments at any time prior to the date that is 90 days following commencement of operations, which is expected in late 2016. The interest capitalized during the year to the investment while the Deerfield Wind Project is under construction amounts to $94 . As of December 31, 2015, Deerfield SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Deerfield SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $321,472 as of December 31, 2015. (c) Natural gas pipeline developments In December 2015, APUC acquired a 4.0% interest in Northeast Supply Pipeline LLC with an option to increase its participation to 10% . Northeast Supply LLC is a new entity undertaking the development, construction and ownership of natural gas transmission pipeline to be constructed between the Bradford and Susquehanna counties in Pennsylvania and Wright, NY. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 4.0% in a limited liability corporation together with the option to increase its participation to 10% provide significant influence. As such, the interest is accounted as an equity method investment. 8. Long-term investments (continued) (c) Natural gas pipeline developments (continued) In November 2014, APUC acquired a 2.5% interest in Northeast Expansion LLC with an option to increase its participation to 10% . Northeast Expansion LLC is a new entity undertaking the development, construction and ownership of a natural gas transmission pipeline to be constructed between Wright, NY and Dracut, MA. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 2.5% in a limited liability corporation together with the option to increase its participation to 10% and the commitment from its New Hampshire subsidiary to a firm gas transportation agreement for service on the pipeline facilities provide significant influence. As such, the interest is accounted as an equity method investment. The total capital investment assuming the Company exercises its right to subscribe for 10% of each pipeline is estimated to be U.S. $520,000 . As of December 31, 2015, APUC had invested U.S. $4,063 (2014 - U.S. $375 ) in the pipeline projects. (d) Development loans The Company entered into a committed loan and credit support facility with Odell SponsorCo and Deerfield SponsorCo (collectively, the “Joint Ventures”). During construction, the Company is obligated to provide Joint Ventures with cash advances and credit support (in the form of letters of credit, escrowed cash, or guarantees) in amounts necessary for the continued development and construction of the Joint Ventures’ Wind Projects. The loan bears interest at an annual rate of 7% - 8% on outstanding principal amount until commercial operation date and 5% thereafter until maturity date, and the letters of credit are charged an annual fee of 2% on their stated amount. Any loan outstanding to Joint Ventures, to the extent not otherwise repaid earlier, is repayable in cash within 30 days of the fifth anniversary of the commercial operation date. As of December 31, 2015, the Company had outstanding loans of U.S. $62,751 from Odell SponsorCo and U.S. $7,281 from Deerfield SponsorCo for development costs of the Joint Ventures’ Wind Projects. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures. As of December 31, 2015, the following credit support was issued by the Company: a U.S. $15,000 letter of credit on behalf of the Odell Wind Project, to the utility under the PPA; a U.S. $1,119 letter of credit on behalf of the the Odell Wind Project pursuant to the generator interconnection agreement; guarantee of the obligations of the Joint Ventures under the wind turbine supply agreements; guarantee of the obligations of the Deerfield Wind Project under the power purchase agreement and decommissioning plan; and, a U.S. $43,238 letter of credit and guarantee of the obligations of Deerfield SponsorCo, to the vendor under the membership interest purchase and contribution agreement. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at U.S. $1,147 using a probability weighted discounted cash flow (level 3). (e) Red Lily I The Red Lily I Partnership (the “Partnership”) is owned by an independent investor. APUC provides operation and supervision services to the Red Lily I project, a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company’s investment in Red Lily I is in the form of participation in a portion of the senior and subordinated debt facilities to the Partnership. The senior debt facility consists of two tranches. A third-party lender advanced $27,000 of senior debt to the Partnership as Tranche 1. In 2011, APUC advanced $13,000 of senior debt as Tranche 2 to the Partnership and received a pre-payment of $1,412 in 2012. The third-party lender has also advanced $4,000 of senior debt Tranche 2 to the Partnership. The Company’s senior loan Tranche 2 to the Partnership earned interest at the rate of 6.31% and was replaced by subordinated debt Tranche 2 on February 23, 2016 as described below. Both tranches of senior debt are secured by substantially all the assets of the Partnership on a pari passu basis. The subordinated loan earns an interest rate of 12.5% , and the principal matures in 2036 but is repayable by the Partnership in whole or in part at any time after 2016 , without a pre-payment premium. The subordinated loan is secured by substantially all the assets of the Partnership but is subordinated to the senior debt. 8. Long-term investments (continued) (e) Red Lily I (continued) Subsequent to year-end, on February 23, 2016, a second tranche of subordinated loan for an amount equal to $15,588 was advanced by the Company. The proceeds from this additional subordinated debt were used by Red Lily I to repay Tranche 2 of the Partnership’s senior debt, including the Company’s portion. In connection with the subordinated debt facility, the Company has an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its Tranche 1 and Tranche 2 subordinated loans, exercisable for a period of 90 days commencing on February 24, 2016. The above notes are secured by the underlying assets of the respective facilities. |
Long-term debt
Long-term debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-term debt | Long-term debt Long-term debt consists of the following: 2015 2014 Generation Group $350,000 revolving credit facility, interest rate is equal to bankers’ acceptance or LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is BA or LIBOR plus 1.45%, maturing July 31, 2019. $ 27,300 $ 23,400 Algonquin Power Co.: 481,991 481,438 Shady Oaks Wind Facility: U.S.$76,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points. This facility was repaid in May 2015. — 88,168 Long Sault Hydro Facility: Senior Debt: $34,760 bonds bearing an interest rate of 10.21%, maturing December 31, 2027. The bonds have interest and principal payments, payable monthly in arrears. 34,760 35,997 Chuteford Hydro Facility: Senior Debt: $2,587 bonds bearing an interest rate of 11.55%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears. 2,587 3,022 Distribution Group U.S.$200,000 revolving credit facility, interest rate is equal to LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is LIBOR plus 1.25%, maturing September 30, 2018. — 23,898 Liberty Utilities Co.: U.S.$ 50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S.$ 25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S.$115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S.$ 15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S.$ 75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; U.S.$ 60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S.$ 25,000, bearing an interest rate of 4.26%, maturing July 31, 2028; U.S.$ 90,000, bearing an interest rate of 4.13%, maturing April 30, 2045; U.S.$ 70,000, bearing an interest rate of 4.13%, maturing July 15, 2045. The notes have interest only payments, payable semi-annually. 721,581 419,876 2015 2014 Calpeco Electric System: U.S.$45,000 bearing an interest rate of 5.19%, maturing December 29, 2020; U.S.$25,000 bearing an interest rate of 5.59%, maturing December 29, 2025. The notes have interest only payments, payable semi-annually in arrears. 96,015 80,368 Liberty Water Co: Senior Unsecured Notes: U.S.$50,000 bearing an interest rate of 5.60% $5,000 matures annually beginning June 20, 2016; $25,000 maturing December 22, 2020. The note bears interest payments semi-annually in arrears. 68,488 57,301 New England Gas System: U.S.$6,500, bearing an interest rate of 9.44%, maturing February 15, 2020; U.S.$7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; U.S.$6,000, bearing an interest rate of 7.24%, maturing December 15, 2027. The notes have interest only payments, payable semi-annually in arrears. 32,130 27,288 Granite State Electric System: Senior Unsecured Notes: U.S.$5,000, bearing an interest rate of 7.37%, maturing November 1, 2023; U.S.$5,000, bearing an interest rate of 7.94%, maturing July 1, 2025; U.S.$5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually. 20,730 17,373 LPSCo Water System: 1999 and 2001 IDA bonds bearing interest rates of 5.85% and 6.71%. This facility was repaid in October 2015. — 12,441 Bella Vista Water System: U.S.$877 Water Infrastructure Financing Authority of Arizona loans bearing interest rates of 6.26% and 6.10%, and maturing March 1, 2020 and December 1, 2017, respectively. The loans have principal and interest payments, payable monthly and quarterly in arrears. 1,213 1,149 $ 1,486,795 $ 1,271,719 Less: current portion (8,945 ) (9,130 ) $ 1,477,850 $ 1,262,589 9. Long-term debt (continued) Certain long-term debt issued at a subsidiary level relating to a specific operating facility is secured by the respective facility with no other recourse to the Company. The loans have certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities. Effective January 1, 2015, the Company applied ASU 2015-03 (note 2(a)) retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt in the table above. Generation Group On October 30, 2015, the Generation Group entered into a new extendible one -year letter of credit facility agreement. The new facility expands the group’s available liquidity by providing for issuances of letters of credit up to a maximum of $50,000 and U.S. $30,000 . If the facility is not extended at maturity, cash collateral equal to letters of credit outstanding at that date would be posted by the Company. On May 12, 2015, the U.S. $76,000 senior debt for the Shady Oaks Wind Facility was repaid. On December 31, 2014, the U.S. $19,200 senior debt for the Sanger thermal facility was repaid. On July 31, 2014, the Company increased the credit available under the senior unsecured revolving credit facility to $350,000 from $200,000 . The larger revolving credit facility will be used to provide additional liquidity in support of the Generation Group ’s development portfolio to be completed over the next three years. The maturity of the revolving credit facility has been extended to July 31, 2018. On May 27, 2015, the Generation Group extended the maturity of its senior unsecured revolving credit facility one year to July 31, 2019 with all other terms remaining the same. On January 17, 2014, the Company issued $200,000 senior unsecured debentures bearing interest at 4.65% and with a maturity date of February 15, 2022. The debentures were sold at a price of $99.864 per $100.00 principal amount. Interest payments are payable on February 15 and August 15 each year, commencing on February 15, 2014. The Company incurred deferred financing costs of $1,568 , which are being amortized to interest expense over the term of the loan using the effective interest rate method. Concurrent with the offering, the Company entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross currency fixed for fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Company’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, an economic hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment (note 24(b)(iii)). Distribution Group On October 1, 2015, the U.S. $9,800 LPSCo Water System IDA bonds were fully repaid. On April 30, 2015, the Distribution Group issued U.S. $160,000 of senior unsecured 30 -year notes bearing a coupon of 4.13% via a private placement in the U.S. The proceeds of the financing will be used in connection with the acquisition of the Park Water System and for general corporate purposes. The funds were drawn in two tranches: U.S. $90,000 was drawn on closing and U.S. $70,000 was drawn on July 15, 2015. 9. Long-term debt (continued) Corporate APUC has a senior unsecured revolving credit of U.S. $65,000 . subsequent to year end the maturity date of the facility was extended by one year to November 19, 2017. As of December 31, 2015 and 2014, no amounts were outstanding under this revolving credit facility. Subsequent to year-end, on February 9, 2016, in connection with the acquisition of Empire (note 3 (a)), the Company obtained $2,200,000 (U.S. $1,600,000 ) in bridge financing commitments from a syndicate of banks. The non-revolving term credit facilities are comprised of a U.S. $1,065,000 debt bridge facility, repayable in full on the first anniversary following its advance, and a U.S. $535,000 equity bridge facility repayable in full on the first anniversary following its advance. On March 1, 2016, upon issuing the Debentures (including the overallotment) (note 25) and receiving the First Instalment, the Company reduced its bridge commitments by $359,950 . Subsequent to year-end, on January, 4, 2016, a subsidiary of APUC entered into a U.S. $235,000 term credit facility with two U.S. banks. The term credit facility is available for acquisitions and general corporate purposes and matures on July 5, 2017. As of December 31, 2015, the Company had accrued $25,161 in interest expense (2014 - $18,770 ). Interest expense on the long-term debt in 2015 was $72,213 (2014 - $64,218 ). Principal payments due in the next five years and thereafter are as follows: 2016 2017 2018 2019 2020 Thereafter Total Generation Group $ 1,816 $ 2,045 $ 137,272 $ 30,152 $ 2,641 $ 375,415 $ 549,341 Distribution Group 7,129 76,358 7,135 7,149 147,640 701,371 946,782 Total $ 8,945 $ 78,403 $ 144,407 $ 37,301 $ 150,281 $ 1,076,786 $ 1,496,123 |
Pension and other post-retireme
Pension and other post-retirement benefits | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Pension and other post-retirement benefits | Pension and other post-employment benefits The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2015 were $ 4,132 (2014 - $ 3,287 ). In conjunction with recent utilities acquisitions, the Company assumed defined benefit pension and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans of the electricity and gas utilities are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31: Pension benefits OPEB 2015 2014 2015 2014 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 241,963 $ 178,113 $ 68,257 $ 45,399 Projected benefit obligation assumed from business combination — 1,022 — — Modifications to pension plan (4,995 ) (560 ) — — Service cost 6,663 4,828 3,093 2,022 Interest cost 9,642 8,549 2,914 2,186 Actuarial loss (gain) (16,098 ) 39,704 (8,466 ) 14,893 Contributions from retirees — — 412 331 Benefits paid (13,024 ) (8,125 ) (2,447 ) (1,586 ) Loss on foreign exchange 45,231 18,432 12,802 5,012 Projected benefit obligation, end of year $ 269,382 $ 241,963 $ 76,565 $ 68,257 Change in plan assets Fair value of plan assets, beginning of year 156,990 139,280 14,295 13,395 Actual return (loss) on plan assets (5,657 ) 6,568 20 1,176 Employer contributions 7,975 5,676 3,028 (222 ) Benefits paid (12,589 ) (7,414 ) (2,036 ) (1,255 ) Gain on foreign exchange 29,453 12,880 2,842 1,201 Fair value of plan assets, end of year $ 176,172 $ 156,990 $ 18,149 $ 14,295 Unfunded status $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) Amounts recognized in the consolidated balance sheets consists of: Current liabilities (470 ) — (1,062 ) (333 ) Non-current liabilities (92,740 ) (84,973 ) (57,354 ) (53,629 ) Net amount recognized $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) The accumulated benefit obligation for the pension plans was $251,932 and $219,007 as of December 31, 2015 and 2014 , respectively. During 2015, the Company permanently froze the accrual of retirement benefits for union participants and most non-union participants under existing plans, effective December 31, 2015 and March 31, 2015, respectively. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of U.S. $3,941 which is recorded as a prior service credit in OCI. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation (continued) The amounts recognized in OCI before tax were as follows: AOCI Pension OPEB Balance, January 1, 2014 $ (14,385 ) $ (9,083 ) Current year net actuarial gain 43,350 14,338 Current year prior service loss (563 ) — Amortization of net actuarial loss 349 641 Balance at December 31, 2014 $ 28,751 $ 5,896 Current year net actuarial loss 1,505 (7,554 ) Current year prior service credits (4,864 ) — Amortization of net actuarial gain (1,358 ) (680 ) Amortization of prior service credits 457 — Balance at December 31, 2015 $ 24,491 $ (2,338 ) The net actuarial loss for the defined benefit pension plans and OPEB that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $632 and $88 , respectively. (b) Assumptions Weighted average assumptions used to determine net benefit cost for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 3.71 % 4.55 % 3.82 % 4.60 % Expected return on assets 6.44 % 7.00 % 5.50 % 5.53 % Rate of compensation increase 3.01 % 2.97 % N/A N/A Health care cost trend rate Before Age 65 7.00 % 7.63 % Age 65 and after 7.00 % 7.63 % Assumed Ultimate Medical Inflation Rate 5.00 % 5.00 % Year in which Ultimate Rate is reached 2019 2019 Weighted average assumptions used to determine net benefit obligation for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 4.16 % 3.71 % 4.23 % 3.80 % Rate of compensation increase 3.00 % 3.01 % N/A N/A Health care cost trend rate Before Age 65 6.50 % 7.00 % Age 65 and after 6.50 % 7.00 % Assumed Ultimate Medical Inflation Rate 4.75 % 5.00 % Year in which Ultimate Rate is reached 2023 2019 10. Pension and other post-employment benefits (continued) (b) Assumptions (continued) The mortality assumption for December 31, 2015 was updated to the projected generationally scale MP-2015, adjusted to reflect the ultimate improvement rates in the 2015 Social Security Administration intermediate assumptions. In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate. The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations. The effect of a one percent change in the assumed health care cost trend rate (“HCCTR”) for 2015 is as follows: 2015 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 10,763 Total service and interest cost 1,111 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (8,687 ) Total service and interest cost (871 ) (c) Benefit costs The following table lists the components of net benefit costs for the pension plans and OPEB recorded as part of operating expenses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition. Pension benefits OPEB 2015 2014 2015 2014 Service cost $ 6,663 $ 4,828 $ 3,093 $ 2,022 Interest cost 9,642 8,549 2,914 2,186 Expected return on plan assets (11,989 ) (10,018 ) (713 ) (628 ) Amortization of net actuarial loss (gain) 1,398 (346 ) 510 (641 ) Amortization of prior service credits (471 ) — — — Net benefit cost $ 5,243 $ 3,013 $ 5,804 $ 2,939 (d) Plan assets The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due. The Company’s target asset allocation is as follows: Asset Class Target (%) Range (%) Equity securities 74 % 49% - 78% Debt securities 26 % 22% - 51% Other — % 0% - 1% 10. Pension and other post-employment benefits (continued) (d) Plan assets (continued) The fair values of investments as of December 31, 2015, by asset category, are as follows: Asset Class Level 1 Percentage Equity securities 138,993 72 % Debt securities 54,542 28 % Other 787 — % As of December 31, 2015, the funds do not hold any material investments in APUC. (e) Cash flows The Company expects to contribute $9,232 to its pension plans and $4,237 to its post-employment benefit plans in 2016. The expected benefit payments over the next ten years are as follows: 2016 2017 2018 2019 2020 2021-2025 Pension plan $ 15,037 $ 13,829 $ 14,474 $ 15,120 $ 15,692 $ 88,692 OPEB 3,113 3,375 3,584 3,804 4,396 25,720 |
Mandatorily redeemable Series C
Mandatorily redeemable Series C preferred shares | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Mandatorily redeemable Series C preferred shares | Mandatorily redeemable Series C preferred shares APUC has 100 redeemable Series C preferred shares issued and outstanding. Thirty-six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for $53,400 per share (fifty-three thousand and four hundred dollars per share) and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of $53,400 per share. As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value. Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are: 2016 $ 979 2017 908 2018 1,068 2019 1,282 2020 1,344 Thereafter to 2031 18,516 Redemption amount 5,340 29,437 Less amounts representing interest (10,910 ) 18,527 Less current portion (979 ) $ 17,548 |
Other assets
Other assets | 12 Months Ended |
Dec. 31, 2015 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other assets | Other assets Other assets consist of the following: 2015 2014 Restricted cash $ 18,999 $ 18,702 Deferred financing costs 3,211 2,428 Other 4,770 4,475 26,980 25,605 Less current portion (464 ) — $ 26,516 $ 25,605 |
Other long-term liabilities and
Other long-term liabilities and deferred credits | 12 Months Ended |
Dec. 31, 2015 | |
Other Liabilities Disclosure [Abstract] | |
Other long-term liabilities and deferred credits | Other long-term liabilities and deferred credits Other long-term liabilities consist of the following: 2015 2014 Advances in aid of construction (a) $ 92,285 $ 81,104 Environmental remediation obligation (b) 71,529 70,072 Asset retirement obligations (c) 17,799 13,884 Customer deposits (d) 15,074 11,713 Deferred income (e) 13,682 13,132 Deferred credits (f) 24,110 19,130 Other 25,277 17,503 259,756 226,538 Less current portion (36,621 ) (49,303 ) $ 223,135 $ 177,235 (a) Advances in aid of construction The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development. In many instances, developer advances can be subject to refund but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 10 to 20 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2015, $4,637 (2014 - $4,608 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation Prior to their acquisition by the Company, EnergyNorth Gas, Granite State Electric and New England Gas Systems were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites. The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $78,495 (2014 - $72,594 ) which at discount rates ranging from 2.5% to 4.2% represents the recorded accrual of $71,529 as of December 31, 2015 (2014 - $70,072 ). Approximately $46,929 is expected to be incurred over the next three years with the balance of cash flows to be incurred over the following 29 years. 13. Other long-term liabilities and deferred credits (continued) (b) Environmental remediation obligation (continued) Changes in the environmental remediation obligation are as follows: 2015 2014 Opening Balance $ 70,072 $ 69,555 Remediation activities (10,621 ) (12,739 ) Accretion 2,147 2,273 Changes in cash flow estimates 3,171 268 Revision in assumptions (5,843 ) 1,954 Purchase price adjustment — 2,726 Foreign exchange rate adjustment 12,603 6,035 Closing Balance $ 71,529 $ 70,072 By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2015, the Company has reflected a regulatory asset of $116,747 (2014 - $102,735 ) for the MGP and related sites (note 7(a)). (c) Asset retirement obligations Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and PCB contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities. During the year, APUC recorded additional asset retirement obligations of $ 506 (2014 - $ 2,570 ) for renewable generation facilities being constructed and accretion expense of $854 (2014 - $527 ). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Deferred income Proceeds received from insurance in advance of repairs, rates collected subject to dispute and other similar proceeds are deferred until they are virtually certain of being realized. (f) Deferred credits Deferred credits include deferred tax credits (note 19) of $3,350 (2014 - $19,130 ). |
Shareholders' capital
Shareholders' capital | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Shareholders' capital | Shareholders’ capital (a) Common shares Number of common shares: 2015 2014 Common shares, beginning of year 238,149,468 206,348,985 Public offering (i) 14,355,000 29,444,000 Issuance of shares under the dividend reinvestment (iv) and employee share purchase plans ((c)(ii)) 3,364,951 2,356,483 Common shares, end of year 255,869,419 238,149,468 14. Shareholders’ capital (continued) (a) Common shares (continued) Authorized APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC, subject to the rights of any shares having priority over the common shares. The Company has a shareholders’ rights plan (the “Rights Plan”) which expires in April 2016. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan. (i) Public offering In December 2015, APUC issued 14,355,000 common shares at $10.45 per share pursuant to a public offering for proceeds of $150,010 before issuance costs of $6,735 or $5,023 net of taxes. In December 2014, APUC issued 10,055,000 common shares at $9.95 per share pursuant to a public offering for proceeds of $100,047 , before issuance costs of $4,243 or $3,021 net of taxes. In September 2014, APUC issued 19,389,000 common shares at $8.90 per share pursuant to a public offering for proceeds of $172,562 , before issuance costs of $7,648 or $5,719 net of taxes. (ii) Subscription receipts On December 29, 2014, the Company received total proceeds of $77,503 from the issuance to Emera Inc. (“Emera”) of 8,708,170 subscription receipts at a price of $8.90 per share in connection with the Odell SponsorCo investment (note 8(a)). At any time, Emera may elect to convert the subscription receipts for no additional consideration on a one-for-one basis into common shares. In the event that Emera has not elected to convert the subscription receipts by November 14, 2016, they will automatically convert into common shares. On December 29, 2014, the Company received total proceeds of $33,000 from the issuance to Emera of 3,316,583 subscription receipts at a price of $9.95 per share in connection with the Park Water System acquisition (note 3(b)). At any time, Emera may elect to convert the subscription receipts for no additional consideration on a one-for-one basis into common shares. In the event that Emera has not elected to convert the subscription receipts by December 29, 2016, they will automatically convert into common shares. (iii) Dividend reinvestment plan The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 292,337 common shares under the dividend reinvestment plan. 14. Shareholders’ capital (continued) (b) Preferred shares APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2015 and 2014: Preferred shares Number of shares Price per share Carrying amount Series A 4,800,000 $ 25 $ 116,546 Series D 4,000,000 $ 25 97,259 $ 213,805 The holders of Series A and Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of $1.125 and $1.25 per share, respectively, for each year up to, but excluding December 31, 2018 and March 31, 2019, respectively. The Series A and Series D dividend rate will reset on those dates and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94% and 3.28% , respectively. The Series A and Series D preferred shares are redeemable at $25 per share at the option of the Company on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. The holders of Series A and Series D preferred shares have the right to convert their shares into cumulative floating rate preferred shares, Series B and Series E, respectively, subject to certain conditions, on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. The Series B and Series E preferred shares will be entitled to receive quarterly floating-rate cumulative dividends, as and when declared by the Board, at a rate equal to the then ninety-day Government of Canada treasury bill yield plus 2.94% and 3.28% , respectively. The holders of Series B and Series E preferred shares will have the right to convert their shares back into Series A and Series D preferred shares on December 31, 2018 and March 31, 2019, respectively and every fifth year thereafter. The Series A, Series B, Series D and Series E preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof. The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets (note 11). (c) Share-based compensation For the year ended December 31, 2015 , APUC recorded $5,330 (2014 - $3,248 ) in total share-based compensation expense detailed as follows: 2015 2014 Share options $ 2,742 $ 1,931 Directors deferred share units 404 273 Employee share purchase 158 116 Performance share units 2,026 928 Total share-based compensation $ 5,330 $ 3,248 The compensation expense is recorded as part of administrative expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant. As of December 31, 2015 , total unrecognized compensation costs related to non-vested options and PSUs were $3,125 and $1,866 , respectively, and are expected to be recognized over a period of 1.74 and 1.63 years, respectively. 14. Shareholders’ capital (continued) (c) Share-based compensation (continued) (i) Share option plan The Company’s share option plan (the “Plan”) permits the grant of share options to key officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 10% of the number of shares outstanding at the time the options are granted. The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options which is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. In the case of qualified retirement, the Board may accelerate the vesting of the unvested options then held by the optionee at the Board’s discretion. All vested options may be exercised within ninety days after retirement. In the case of death, the options vest immediately and the period over which the options can be exercised is one year. In the case of disability, options continue to vest and be exercisable in accordance with the terms of the grant and the provisions of the plan. Employees have up to thirty days to exercise vested options upon resignation or termination. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the adjusted historical volatility of the Company’s shares. The expected life was estimated to equal the contractual life of the options. The dividend yield rate was based upon recent historical dividends paid on APUC shares. The following assumptions were used in determining the fair value of share options granted: 2015 2014 Risk-free interest rate 1.3 % 2.0 % Expected volatility 38 % 38 % Expected dividend yield 4.0 % 3.8 % Expected life 8 years 8 years Weighted average grant date fair value per option $ 2.45 $ 2.00 Share option activity during the years is as follows: Number of awards Weighted average exercise price Weighted average remaining contractual term (years) Aggregate intrinsic value Balance at January 1, 2014 4,567,129 $ 5.70 5.45 $ 7,814 Granted 969,998 7.95 8.00 — Balance at December 31, 2014 5,537,127 $ 6.09 4.96 $ 19,648 Granted 1,627,525 9.75 8.00 — Balance at December 31, 2015 7,164,652 $ 6.92 4.74 $ 28,561 Exercisable at December 31, 2015 4,618,323 $ 5.74 3.55 $ 23,898 14. Shareholders’ capital (continued) (c) Share-based compensation (continued) (ii) Employee share purchase plan Under the Company’s employee share purchase plan (“ESPP”), eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match (a) 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually, for Canadian employees, and (b) 15% of the employee contribution amount for the first fifteen thousand dollar per employee contributed annually, for U.S. employees. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the contribution date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX by an independent broker. The aggregate number of common shares reserved for issuance from treasury by APUC under the ESPP shall not exceed 2,000,000 common shares. The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2015, a total of 111,355 common shares (2014 - 93,598 ) were issued to employees under the ESPP. (iii) Directors deferred share units Under the Company’s Deferred Share Unit Plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2015, 157,471 (2014 - 110,241 ) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. (iv) Performance share units The Company offers a PSU plan to its employees as part of the Company’s long-term incentive program. PSUs are granted annually for three -year overlapping performance cycles. PSUs vest at the end of the three-year cycle and will be calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 0% to 197.5% of the number of PSUs granted. Dividends accumulating during the vesting period are converted to PSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs have voting rights. Any PSUs not vested at the end of a performance period will expire. The PSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. Compensation expense associated with PSUs is recognized rateably over the performance period and assumes that performance goals will be achieved at 100% . If goals met differ, compensation cost recognized is adjusted to reflect the performance conditions achieved. 14. Shareholders’ capital (continued) (c) Share-based compensation (continued) (iv) Performance share units (continued) A summary of the PSUs follows: Number of awards Weighted average grant-date fair value Weighted average remaining contractual term (years) Aggregate intrinsic value Balance at January 1, 2014 66,195 $ 6.57 0.62 $ 486 Granted 407,962 8.22 3.00 3,333 Exercised (22,665 ) 6.13 — (185 ) Forfeited (11,406 ) 8.22 — (93 ) Balance at December 31, 2014 440,086 $ 6.57 1.81 $ 4,242 Granted, including dividends 212,250 9.72 2.62 — Exercised (41,131 ) 6.86 — 381 Forfeited (47,089 ) 8.30 — — Balance at December 31, 2015 564,116 $ 7.59 1.63 $ 6,155 Exercisable at December 31, 2015 157,972 $ 8.22 — $ 1,723 |
Accumulated other comprehensive
Accumulated other comprehensive income (loss) | 12 Months Ended |
Dec. 31, 2015 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Accumulated other comprehensive income (loss) | Accumulated other comprehensive income (loss) AOCI consists of the following balances, net of tax: Foreign currency cumulative translation Unrealized gain on cash flow hedges Net change on available-for-sale investments Pension and post-employment actuarial changes Total Balance, January 1, 2014 $ (57,471 ) $ 11,840 $ — $ 14,221 $ (31,410 ) OCI (loss) before reclassifications 68,938 3,358 519 (35,396 ) 37,419 Amounts reclassified — 5,423 (518 ) (273 ) 4,632 Net current period OCI 68,938 8,781 1 (35,669 ) 42,051 Acquisition of non-controlling interest 21,029 2,543 — — 23,572 Balance, December 31, 2014 $ 32,496 $ 23,164 $ 1 $ (21,448 ) $ 34,213 OCI before reclassifications 228,861 21,896 (73 ) 6,487 257,171 Amounts reclassified — (5,731 ) — 1,084 (4,647 ) Net current period OCI $ 228,861 $ 16,165 $ (73 ) $ 7,571 $ 252,524 Balance, December 31, 2015 $ 261,357 $ 39,329 $ (72 ) $ (13,877 ) $ 286,737 Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales while those for pension and post-employment actuarial changes affected administrative expenses. |
Dividends
Dividends | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Cash Dividends [Abstract] | |
Dividends | Dividends All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividend on its commons shares in U.S. dollars. Dividends declared in Canadian equivalent dollars during the year were as follows: 2015 2014 Dividend Dividend per share Dividend Dividend per share Common shares $ 124,831 $ 0.4867 $ 83,097 $ 0.3695 Series A preferred shares $ 5,400 $ 1.1250 $ 5,400 $ 1.1250 Series D preferred shares $ 5,000 $ 1.2500 $ 4,103 $ 1.0257 |
Related party transactions
Related party transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related party transactions | Related party transactions Emera Inc. A member of the Board of APUC is an executive at Emera. During 2015, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), and Bangor Hydro (“BH”) subsidiaries of Emera, amounting to U.S.$ 6,658 (2014 - U.S.$ 9,821 ). During 2015, Liberty Utilities purchased natural gas amounting to U.S. $ 2,292 (2014 - U.S. $3,961 ) from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process the results of which were approved by the regulator in the relevant jurisdiction. There was U.S. $491 included in accruals in 2015 (2014 - U.S.$ nil ) related to these transactions at the end of the years. Equity-method investments The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $2,021 (2014 - $189 ) during the year. Senior Executives As at December 31, 2015, $ nil (December 31, 2014 - $47 ) was due from Algonquin Power Systems Ltd., a corporation partially owned by Ian Robertson and Chris Jarratt (collectively “Senior Executives”). Chartered Aircraft As part of its normal business practice, APUC has utilized chartered aircraft when it is beneficial to do so and had previously entered into a block time agreement to charter aircraft in which Senior Executives have a partial ownership. The Company terminated the agreement effective June 28, 2015 and paid a usage shortfall fee of $13 . During the year ended December 31, 2015, APUC reimbursed direct costs in connection with the use of the aircraft prior to termination of the block time agreement of $507 (2014 - $721 ). Office Facilities Until the fourth quarter of 2014, APUC had leased its head office facilities from an entity partially owned by Senior Executives. During the fourth quarter of 2014, APUC terminated the related party lease and moved all head office employees into new premises owned by the Company. Base lease costs for the year ended December 31, 2015 were $ nil (2014 - $ 356 ). Other A spouse of one of the Senior Executives was employed to provide market research services to certain subsidiaries of the Company. During the year ended December 31, 2015, APUC paid $22 (2014 - $192 ) in relation to these services. The spouse is no longer employed by the Company. Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives. APC owns the partnership interest in the 18MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction is expected to be settled in 2016. The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions. |
Non-controlling Interests
Non-controlling Interests | 12 Months Ended |
Dec. 31, 2015 | |
Noncontrolling Interest [Abstract] | |
Non-controlling Interests | Non-controlling interests Net loss attributable to non-controlling interests consists of the following: 2015 2014 Net earnings attributable to Class B partnership units of Wind Portfolio SponsorCo (i) $ — $ 3,484 Net loss attributable to Class A partnership units (ii) (33,942 ) (27,199 ) Other net earnings attributable to non-controlling interests 1,966 1,529 Total net loss attributable to non-controlling interests $ (31,976 ) $ (22,186 ) (i) On March 31, 2014, the Company acquired the remaining Class B partnership units of Wind Portfolio SponsorCo from the non-controlling interest holder. As a result of the transaction, the Company now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units (note 3(h)). (ii) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Senate, Minonk and Sandy Ridge wind facilities and, beginning December 31, 2014, the Bakersfield Solar facility are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(q). |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income taxes | Income taxes The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2014 - 26.5% ). The differences are as follows: 2015 2014 Expected income tax expense at Canadian statutory rate $ 34,516 $ 19,199 Increase (decrease) resulting from: Recognition of deferred credit (2,448 ) (5,763 ) Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (3,855 ) (1,677 ) Non-taxable corporate dividend (3,311 ) (2,618 ) Non-controlling interests share of income 12,511 8,824 Production tax credit (254 ) (339 ) Allowance for equity funds used during construction (935 ) (746 ) State taxes 733 604 Adjustment relating to prior periods 2,431 — CRA Settlement 2,709 — Other 1,616 (677 ) Income tax expense $ 43,713 $ 16,807 For the years ended December 31, 2015 and 2014, earnings from continuing operations before income taxes consist of the following: 2015 2014 Canadian operations $ 28,481 $ 11,930 U.S. operations 101,768 60,519 $ 130,249 $ 72,449 19. Income taxes (continued) Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2015 Canada $ 5,272 $ 1,959 $ 7,231 United States 2,038 34,444 36,482 $ 7,310 $ 36,403 $ 43,713 Year ended December 31, 2014 Canada $ 5,660 $ (3,538 ) $ 2,122 United States (1,986 ) 16,671 14,685 $ 3,674 $ 13,133 $ 16,807 The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are presented below: 2015 2014 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 396,727 $ 319,056 Pension and OPEB 57,969 54,458 Acquisition-related costs 6,035 5,168 Environmental obligation 28,230 28,555 Production tax credit 3,027 2,098 Reserves not currently deductible 2,503 2,315 Other 4,970 3,988 Total deferred income tax assets 499,461 415,638 Less valuation allowance (17,478 ) (15,534 ) Total deferred tax assets 481,983 400,104 Deferred tax liabilities: Property, plant and equipment (544,616 ) (387,931 ) Intangible assets (2,760 ) (2,752 ) Outside basis in partnership (32,221 ) (15,194 ) Regulatory accounts (28,270 ) (49,399 ) Financial derivatives (31,806 ) (15,013 ) Total deferred tax liabilities (639,673 ) (470,289 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 18,109 $ 64,275 Deferred tax liabilities (175,799 ) $ (134,460 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) 19. Income taxes (continued) The valuation allowance for deferred tax assets as at December 31, 2015 was $ 17,478 (2014 - $15,534 ). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment. As of December 31, 2015, the Company had non-capital losses carried forward available to reduce future year’s taxable income, which expire as follows: Year of expiry Non-capital loss carryforwards 2016 $ — 2017 and onwards 967,499 $ 967,499 On June 26, 2015, the Company entered into an agreement with the Canada Revenue Agency (“CRA”) regarding a CRA’s proposal to reassess APUC’s 2009 through 2013 income tax filings in relation to a unit exchange transaction that occurred on October 27, 2009. The agreement resulted in a $16,042 reduction in the APUC’s deferred tax assets and a proportional reduction of $13,333 in its deferred credits (note 13(f)). Consequently, the Company’s results for 2015 reflect a $2,709 net non-cash charge to deferred income tax expense. The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of its subsidiaries. Deferred income taxes have not been provided on approximately $64,678 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable. |
Basic and diluted net earnings
Basic and diluted net earnings per share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share, Basic and Diluted [Abstract] | |
Basic and diluted net earnings per share | Basic and diluted net earnings per share Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and subscription receipts outstanding (note 14 (a)(ii)). Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options. The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2015 2014 Net earnings attributable to shareholders of APUC $ 117,480 $ 75,701 Series A Preferred shares dividend 5,400 5,400 Series D Preferred shares dividend 5,000 4,103 Net earnings attributable to common shareholders of APUC $ 107,080 $ 66,198 Discontinued operations (1,032 ) (2,127 ) Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 108,112 $ 68,325 Weighted average number of shares Basic 253,172,088 213,953,870 Effect of dilutive securities 3,344,632 2,387,722 Diluted 256,516,720 216,341,592 The shares potentially issuable as a result of 1,627,525 share options (2014 - 1,786,401 ) are excluded from this calculation as they are anti-dilutive. |
Segmented information
Segmented information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segmented information | Segmented information The Company’s management’s reporting structure is aligned under three business units: Generation, Transmission and Distribution. During the fourth quarter, Management determined that each business unit represents a reporting segment. The comparative information for 2014 has been reclassified to conform with the composition of the reporting segments presented in the current year. Generation , owns or has interests in hydroelectric, solar, wind power facilities and co-generation. Distribution operates electric, natural gas and water distribution utilities. Finally, Transmission invests in rate regulated electric transmission and natural gas pipeline systems. The Transmission segment includes the equity method investment in the Natural Gas Pipeline Development (note 8(c)) which is not yet significant and as a result is not presented separately in the tables below but grouped within Corporate. For purposes of evaluating divisional performance, the Company allocates the realized portion of any gains or losses on financial instruments to specific divisions. The unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The results of operations and assets for these segments are reflected in the tables below. Year ended December 31, 2015 Generation Distribution Corporate Total Revenue $ 244,751 $ 783,104 $ — $ 1,027,855 Fuel and power purchased 27,990 348,883 — 376,873 Net revenue 216,761 434,221 — 650,982 Operating expenses 63,601 213,750 1,210 278,561 Administrative expenses 10,822 21,570 8,283 40,675 Depreciation and amortization 67,293 82,513 — 149,806 Gain on foreign exchange — — (2,631 ) (2,631 ) Operating income (loss) from continuing operations 75,045 116,388 (6,862 ) 184,571 Interest expense 29,395 34,971 1,627 65,993 Interest, dividend, equity and other income (1,154 ) (3,974 ) (3,967 ) (9,095 ) Other expenses (gain) (5,623 ) 391 2,656 (2,576 ) Earnings (loss) before income taxes $ 52,427 $ 85,000 $ (7,178 ) $ 130,249 Property, plant and equipment $ 1,895,617 $ 1,914,980 $ 63,087 $ 3,873,684 Equity-method investees 44,638 769 7,066 52,473 Total assets 2,345,905 2,532,894 112,926 4,991,725 Capital expenditures 55,992 141,445 6,758 204,195 21. Segmented information (continued) Year ended December 31, 2014 Generation Distribution Corporate Total Revenue $ 218,765 $ 722,849 $ — $ 941,614 Fuel and power purchased 39,264 381,622 — 420,886 Net revenue 179,501 341,227 — 520,728 Operating expenses 55,482 178,248 308 234,038 Administrative expenses 13,457 19,947 1,288 34,692 Depreciation and amortization 58,248 53,671 2,128 114,047 Gain on foreign exchange — — (1,112 ) (1,112 ) 52,314 89,361 (2,612 ) 139,063 Interest expense 33,868 27,139 1,411 62,418 Interest, dividend and other income (1,187 ) (3,369 ) (3,202 ) (7,758 ) Other expense (gain) 48 300 11,606 11,954 Earnings (loss) before income taxes $ 19,585 $ 65,291 $ (12,427 ) $ 72,449 Property, plant and equipment $ 1,687,465 $ 1,531,166 $ 59,791 $ 3,278,422 Equity-method investees 3,520 500 2,578 6,598 Total assets 1,896,265 2,098,244 108,339 4,102,848 Capital expenditures 201,063 176,849 54,461 432,373 The majority of non-regulated energy sales are earned from contracts with large public utilities. The following utilities contributed more than 10% of these total revenues in either 2015 or 2014: Hydro Québec 13% (2014 - 11% ); Manitoba Hydro 13% (2014 - 13% ); PJM 14% (2014 - 10% ); and ComEd 11% (2014 - 10% ). The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations. APUC operates in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows: 2015 2014 Revenue Canada $ 86,977 $ 92,267 United States 940,878 849,347 $ 1,027,855 $ 941,614 Property, plant and equipment Canada $ 592,598 $ 590,580 United States 3,281,086 2,687,842 $ 3,873,684 $ 3,278,422 Intangible assets Canada $ 40,186 $ 25,601 United States 37,777 28,410 $ 77,963 $ 54,011 Revenue is attributed to the two countries based on the location of the underlying generating and utility facilities. |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and contingencies | Commitments and contingencies (a) Contingencies APUC and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider APUC’s exposure to such litigation to be material to these financial statements, with the exception of those matters described below. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable. On October 21, 2011, the Quebec Court of Appeal ordered a subsidiary of APUC to pay approximately $5,400 (including interest) to the Government of Quebec relating to water lease payments that the APUC subsidiary has been paying to the St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management in prior years. The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position. As a result, the probability of loss, if any, and its quantification cannot be estimated at this time but could range from $ nil to $6,800 . In 2012, the Company paid an amount of $1,884 to the Government of Quebec in relation to the early years covered by the claim in order to mitigate the impact of accruing interests on any amount ultimately determined to be payable or recoverable. (b) Commitments In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3, 8 and 25, the following significant commitments exist as of December 31, 2015. As a result of the dam safety legislation passed in Quebec (Bill C-93), APUC has completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec. The assessments have identified a number of remedial measures required to meet the new safety standards. APUC currently estimates further capital expenditures of approximately $ 8,000 over a period of 4 years related to compliance with the legislation. APUC has outstanding purchase commitments for power purchases, gas delivery, service and supply, service agreements, capital project commitments and operating leases. Detailed below are estimates of future commitments under these arrangements: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total Power purchase (i) $ 82,403 $ 52,644 $ 55,599 $ 59,165 $ 59,791 $ — $ 309,602 Gas supply and service agreements (ii) 66,264 46,673 36,621 35,482 32,070 82,509 299,619 Service agreements 38,335 38,151 35,019 35,734 35,955 518,193 701,387 Capital projects 35,842 7,571 71 71 71 18 43,644 Operating leases 5,863 5,319 4,866 4,754 4,793 106,210 131,805 Total $ 228,707 $ 150,358 $ 132,176 $ 135,206 $ 132,680 $ 706,930 $ 1,486,057 (i) Power purchase: APUC’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2015. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power. |
Non-cash operating items
Non-cash operating items | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Changes In Non Cash Operating Items [Abstract] | |
Non-cash operating items | Non-cash operating items The changes in non-cash operating items consist of the following: 2015 2014 Accounts receivable $ 6,715 $ (23,640 ) Natural gas in storage 3,049 (5,942 ) Supplies and consumable inventory (2,968 ) (3,861 ) Income taxes receivable (2,529 ) (189 ) Prepaid expenses (7,833 ) 827 Accounts payable (18,261 ) 54,299 Accrued liabilities (28,495 ) 32,520 Current income tax liability 1,820 (1,527 ) Net regulatory assets and liabilities 37,353 (54,277 ) $ (11,149 ) $ (1,790 ) |
Financial instruments
Financial instruments | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Financial instruments | Financial instruments (a) Fair value of financial instruments 2015 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 119,383 $ 126,468 $ — $ 126,468 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 88,357 88,357 — — 88,357 Commodity contracts for regulated operations 4 4 — 4 — Total derivative financial instruments 88,361 88,361 — 4 88,357 Total financial assets $ 207,744 $ 214,829 $ — $ 126,472 $ 88,357 Long-term debt $ 1,486,795 $ 1,547,346 $ 511,829 $ 1,035,517 $ — Preferred shares, Series C 18,527 17,303 — 17,303 — Derivative financial instruments: Energy contracts designated as a cash flow hedge 446 446 — — 446 Cross-currency swap designated as a net investment hedge 101,559 101,559 — 101,559 — Interest rate swap designated as a hedge 9,659 9,659 — 9,659 — Currency forward contract not designated as a hedge 1,918 1,918 — 1,918 — Commodity contracts for regulated operations 1,676 1,676 — 1,676 — Total derivative financial instruments 115,258 115,258 — 114,812 446 Total financial liabilities $ 1,620,580 $ 1,679,907 $ 511,829 $ 1,167,632 $ 446 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2014 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 39,510 $ 41,339 $ — $ 41,339 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 41,966 41,966 — — 41,966 Energy contracts not designated as a cash flow hedge 504 504 — — 504 Total derivative financial instruments 42,470 42,470 — — 42,470 Total financial assets $ 81,980 $ 83,809 $ — $ 41,339 $ 42,470 Long-term debt $ 1,271,719 $ 1,363,934 $ 520,142 $ 843,792 $ — Preferred shares, Series C 18,693 18,209 — 18,209 — Derivative financial instruments: Cross-currency swap designated as a net investment hedge 36,276 36,276 — 36,276 — Interest rate swaps designated as a hedge 4,684 4,684 — 4,684 — Interest rate swaps not designated as a hedge 1,383 1,383 — 1,383 — Commodity contracts for regulated operations 2,928 2,928 — 2,928 — Total derivative financial instruments 45,271 45,271 — 45,271 — Total financial liabilities $ 1,335,683 $ 1,427,414 $ 520,142 $ 907,272 $ — 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2015 and 2014 due to the short-term maturity of these instruments. Notes receivable fair values (level 2) have been determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. The Company’s level 2 fair value of long-term debt at fixed interest rates and Series C preferred shares has been determined using a discounted cash flow method and current interest rates. The Company’s level 2 fair value derivative instruments primarily consist of swaps, options and forward physical deals where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves which are observable in the marketplace. The Company’s level 3 instruments consist of energy contracts for electricity sales. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $18.39 to $138.3 with a weighted average of $39.98 as of December 31, 2015. The processes and methods of measurement are developed using the market knowledge of the trading operations within the Company and are derived from observable energy curves adjusted to reflect the illiquid market of the hedges and, in some cases, the variability in deliverable energy. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). Fair value estimates are made at a specific point in time, using available information about the financial instrument. These estimates are subjective in nature and often cannot be determined with precision. The Company’s accounting policy is to recognize transfers between levels of the fair value hierarchy on the date of the event or change in circumstances that caused the transfer. There was no transfer into or out of level 1, level 2 or level 3 during the years ended December 31, 2015 and 2014. (b) Derivative instruments Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period. (i) Commodity derivatives – regulated accounting The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated gas service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers. The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts: 2015 Financial contracts: Gas swaps 1,086,228 Gas options 412,369 1,498,597 The accounting for these derivative instruments is subject to guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 7(c)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact. 24. Financial instruments (continued) (b) Derivative instruments (continued) (i) Commodity derivatives – regulated accounting (continued) The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 2015 2014 Regulatory assets: Gas swap contracts U.S. $ 1,058 U.S. $ 2,178 Gas option contracts U.S. $ 154 U.S. $ 346 Regulatory liabilities: Gas swap contracts U.S. $ 3 U.S. $ — Gas option contracts U.S. $ — U.S. $ — (ii) Cash flow hedges The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities and at one of its hydro facilities no longer subject to a power purchase agreement by entering into the following long-term energy derivative contracts. Notional quantity (MW-hrs) Expiry Receive average prices (per MW-hr) Pay floating price (per MW-hr) 49,135 December 2016 $ 68.56 AESO 801,098 December 2022 U.S. $ 42.81 PJM Western HUB 3,419,634 December 2022 U.S. $ 30.25 NI HUB 3,997,509 December 2027 U.S. $ 36.46 ERCOT North HUB As of December 31, 2015, an amount receivable under the derivatives for Sandy Ridge, Senate and Minonk Wind Facilities of $4,882 (2014 - $156 ) was held as collateral by the counterparty. On November 14, 2014, the Company entered into a 10 -year forward-starting interest rate swap beginning on July 25, 2018 in order to reduce the interest rate risk related to the probable issuance on that date of a 10 -year $135,000 bond. The change in fair value resulted in a loss of $4,974 for the year ended December 31, 2015 (2014 - loss of $4,684 ), which is recorded in OCI. The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2015 2014 Effective portion of cash flow hedge, loss (gain) $ 21,932 $ (2,592 ) Amortization of cash flow hedge (36 ) (32 ) Loss (gain) reclassified from AOCI (5,731 ) 5,423 $ 16,165 $ 2,799 Less non-controlling interest — 5,982 OCI attributable to shareholders of APUC $ 16,165 $ 8,781 The Company expects $14,975 of unrealized gains currently in AOCI to be reclassified into non-regulated energy sales within the next twelve months, as the underlying hedged transactions settle. 24. Financial instruments (continued) (b) Derivative instruments (continued) (iii) Foreign exchange hedge of net investment in foreign operation The Company is exposed to currency fluctuations from its U.S. based operations. APUC manages this risk primarily through the use of natural hedges by using U.S. long-term debt to finance its U.S. operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major Canadian financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts. The Company designates the amounts drawn on the Generation Group’s revolving credit facility denominated in U.S. dollars in excess of the principal amount on the USD loans receivable from Odell and Deerfield Wind SponsorCo as a hedge of the foreign currency exposure of its net investment in the Generation Group’s U.S. operations. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of nil for the year ended December 31, 2015 (2014 - $2,727 ) was recorded in OCI. Concurrent with its $150,000 and $200,000 debenture offerings in December 2012 and January 2014, respectively, the Company entered into cross currency swaps, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Generation Group ’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $68,195 (2014 - loss of $ 28,537 ) was recorded in OCI in 2015. (iv) Other derivatives The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility are expected to provide a portion of the energy required to service these customers, APUC anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy. This risk is mitigated though the use of short-term financial forward energy purchase contracts which are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contract term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur. The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligation, including certain project specific debt and its revolving credit facilities, its interest rate swaps as well as interest earned on its cash on hand. The Company currently hedges some of that risk (note 24(b)(ii)). The Company was party to an interest rate swap whereby the Company paid a fixed interest rate of 4.47% on a notional amount of $58,791 and received floating interest at 90 day CDOR. The swap expired on September 2015. As of December 31, 2014, the estimated fair value of the interest rate swap was a liability of $1,383 . This interest rate swap was not accounted for as a hedge. The Company is exposed to foreign exchange fluctuations related to U.S dollar denominated development loans from projects accounted for as equity investments (note 8(d)). This risk is mitigated through the use of a currency forward contract to sell U.S. $63,400 for $85,812 on April 30, 2016. As of December 31, 2015, the estimated fair value of the instrument was a liability of $1,918 . This currency forward contract was not accounted for as a hedge. For derivatives that are not designated as hedges and for the ineffective portion of gains and losses on derivatives that are accounted for as hedges, the changes in the fair value are immediately recognized in earnings. 24. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives (continued) The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2015 2014 Change in unrealized loss (gain) on derivative financial instruments: Interest rate swaps $ (1,383 ) $ (1,797 ) Energy derivative contracts 886 3,386 Currency forward contract 1,918 — Total change in unrealized loss (gain) on derivative financial instruments $ 1,421 $ 1,589 Realized loss (gain) on derivative financial instruments: Interest rate swaps 1,498 1,962 Energy derivative contracts (579 ) (3,627 ) Total realized loss (gain) on derivative financial instruments $ 919 $ (1,665 ) Loss (gain) on derivative financial instruments not accounted for as hedges 2,340 (76 ) Ineffective portion of derivative financial instruments accounted for as hedges (2,610 ) 1,451 $ (270 ) $ 1,375 Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments $ (2,188 ) $ 1,375 Loss on foreign exchange $ 1,918 $ — $ (270 ) $ 1,375 (c) Risk management In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks. Credit risk Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders all of which have a credit rating of A or better. The Company does not consider the risk associated with the Generation Group accounts receivable to be significant as over 80% of revenue from power generation is earned from large utility customers having a credit rating of BBB or better, and revenue is generally invoiced and collected within 45 days. The remaining revenue is primarily earned by the Distribution Group which consists of water and wastewater, electric and gas utilities in the United States. In this regard, the credit risk related to Distribution Group accounts receivable balances of U.S. $91,308 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, the state regulators of the Distribution Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers. 24. Financial instruments (continued) (c) Risk management (continued) Credit risk (continued) As of December 31, 2015, the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2015 Canadian $ US $ Cash and cash equivalents and restricted cash $ 39,972 $ 74,696 Accounts receivable 15,016 129,791 Allowance for doubtful accounts (5,756 ) Notes receivable 19,664 72,052 $ 74,652 $ 270,783 In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Liquidity risk Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2015, in addition to cash on hand of $124,353 the Company had $580,901 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants which may limit amounts available to be drawn. The Company’s liabilities mature as follows: Due less than 1 year Due 2 to 3 years Due 4 to 5 years Due after 5 years Total Long-term debt obligations $ 8,945 $ 222,810 $ 187,582 $ 1,076,786 $ 1,496,123 Advances in aid of construction 1,347 — — 90,938 92,285 Interest on long-term debt 74,324 138,841 117,328 333,606 664,099 Purchase obligations 243,748 — — — 243,748 Environmental obligation 5,435 41,494 1,753 29,813 78,495 Derivative financial instruments: Cross-currency swap 4,828 8,963 7,508 80,260 101,559 Interest rate swaps — 9,659 — — 9,659 Currency forward 1,918 — — — 1,918 Energy derivative and commodity contracts 1,885 237 — — 2,122 Other obligations 12,808 — — 40,694 53,502 Total obligations $ 355,238 $ 422,004 $ 314,171 $ 1,652,097 $ 2,743,510 |
Subsequent event - Convertible
Subsequent event - Convertible Unsecured Subordinated Debentures | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent event - Convertible Unsecured Subordinated Debentures | Subsequent event - Convertible Unsecured Subordinated Debentures Subsequent to year-end, on March 1, 2016, the Company completed the sale of $1,000,000 aggregate principal amount of 5.0% convertible unsecured subordinated debentures. The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of Empire. On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional Debentures bringing the total amount of Debentures under the Debenture Offering to $1,150,000 . The Debentures will mature on March 31, 2026 and bear interest at an annual rate of 5% per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0% . Based on the first instalment of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 15% , and the effective annual yield thereafter is 0% . If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date (the “Make-Whole Payment”). No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Prior to the closing of the acquisition, the Company will at all times have cash on hand or maintain readily available capacity under the revolving credit facilities of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option. At the option of the holders and provided that payment of the Final Instalment has been made, each Debenture will be convertible into common shares of the Company at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $10.60 per common share. Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions necessary to approve the acquisition of Empire will not be satisfied; (ii) termination of the acquisition agreement; and (iii) September 11, 2017 if notice of the Final Instalment Date has not been given to holders on or before September 8, 2017. Upon any such redemption, the Company will pay for each Debenture $333 plus accrued and unpaid interest to the holder of the instalment receipt. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest, which accrued prior to and including the Final Instalment Date. At maturity, the Company will have the right to pay the principal amount due in cash or in common shares. In the case of common shares, such shares will be valued at 95% of their weighted average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date. |
Comparative figures
Comparative figures | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Comparative figures | Comparative figures Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year. |
Significant accounting polici35
Significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of preparation | Basis of preparation The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission. |
Basis of consolidation | Basis of consolidation The accompanying consolidated financial statements of APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(l)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(q)). |
Business combinations, intangible assets and goodwill | Business combinations, intangible assets and goodwill The Company accounts for acquisitions of entities or assets which meet the definition of a business as business combinations. The determination of whether the definition of a business has been met for a development stage project depends on the stage of development (permitting, customer contracting, financing, construction) and the significance of the development risk with respect to achieving commercial operation. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date. Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisitions costs. Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is not included in the rate-base on which regulated utilities are allowed to earn a return and is not amortized. During the fourth quarter of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. |
Accounting for rate regulated operations | Accounting for rate regulated operations The regulated utility operating companies owned by the Company are subject to rate regulation generally overseen by the public utility commission of the states in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated utility operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”)ASC Topic 980, Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment. In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets (liabilities). The impact could be material to the Company’s reported financial condition and results of operations. The electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”) and National Association of Regulatory Utility Commissioners. |
Cash and cash equivalents | Cash and cash equivalents Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less. |
Restricted cash | Restricted cash Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements and requirements of ISO New England, Inc. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash as part of other assets (note 12) in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC. |
Accounts receivable | Accounts receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers. |
Natural gas in storage | Natural gas in storage Natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders (note 7(c)) and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments. Accordingly, the recoverable value of gas in storage does not fall below the cost to the Company. |
Supplies and consumables inventory | Supplies and consumables inventory Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or become obsolete. These items are stated at the lower of cost and replacement cost. Supplies and consumables inventory is included in other current assets. |
Property, plant and equipment | Improvements that increase or prolong the service life or capacity of an asset are capitalized. Cost incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Investment tax credits and government grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 13(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Investment tax credits and government grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. 1. Significant accounting policies (continued) (j) Property, plant and equipment (continued) The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. Effective January 1, 2015, the Company changed the depreciation method from the straight-line method to the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component. This change in the depreciation method results from having better information on the consumption of the benefits of certain individual components that are directly related to production and separately identified in the records of the Company. The change is being recognized prospectively.The impact of the change on the operating results for 2015 was a reduction of depreciation expense of $3,418 . The impact on basic and diluted net earnings per share for 2015 was an increase of $0.01 . The change is not expected to materially affect net earnings or net earnings per share on an annual basis. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Distribution Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. Property, plant and equipment Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority authorized and has committed to the funding of the project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate-regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory asset when it is determined that recovery of such costs through regulated revenue of the completed project is probable. The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under capital leases are initially recorded at cost determined as the present value of minimum lease payments. AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest, dividend, equity and other income on the consolidated statements of operations. 2015 2014 Interest capitalized on non-regulated property $ 1,189 $ 3,584 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,657 1,577 Allowance for equity funds 2,425 1,910 Total $ 5,271 $ 7,071 |
Impairment of long-lived assets | Impairment of long-lived assets APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. Assets held and used: Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. Assets held for sale: Recoverability of assets held for sale is measured by comparing the carrying amount of an asset to its fair value less cost to sell. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value less estimated costs to sell. |
Variable interest entities | Variable interest entities The Company performs analysis to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8(a) and (b)). The Company has equity and notes receivable interests in two power generating facilities. APUC has determined that both entities are considered a VIE mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As APUC has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entity, the Company is considered the primary beneficiary. |
Long-term investments and notes receivable | Long-term investments and notes receivable Investments in which APUC has significant influence but not control are accounted using the equity method. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. APUC records its share in the income or loss of its investees in interest, dividend, equity and other income in the consolidated statements of operations. Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company acquired these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned. If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. |
Pension and other post employment plans | Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, and other post-employment benefit (“OPEB”) plans for its various employee groups in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans and OPEB plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and are recognized as part of administrative expenses in the consolidated statements of operations. |
Asset retirement obligations | Asset retirement obligations The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Actual expenditures incurred are charged against the obligation. |
Stock based compensation | Share-based compensation The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. Equity classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expense in the consolidated statements of operations and contributed surplus in equity. Contributed surplus is reduced as the awards are exercised, and the amount initially recorded in contributed surplus is credited to common shares. |
Noncontrolling interests | Non-controlling interests Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests. If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company. Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units”) which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV method uses a balance sheet approach, which measures the allocation of income or loss of the Class A partnership units in each period by calculating the change in the amount of distribution the partners would contractually be entitled to based on a hypothetical liquidation of the book value carrying amounts of the entity at the beginning of a reporting period compared to the end of that period (note 18). Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification. |
Recognition of revenue | Recognition of revenue Revenue derived from non-regulated energy generation sales, which are mostly under long-term power purchase contracts, is recorded at the time electrical energy is delivered. Revenue related to utility electricity and natural gas sales and distribution are recorded when the electricity or natural gas is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Revenue for the Company’s Calpeco Electric System, Peach State Gas System and New England Gas System is subject to a revenue decoupling mechanism approved by their respective regulator which require to charge approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7(e)). Water reclamation and distribution revenues are recorded when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented. Revenue is recorded net of sales taxes. |
Foreign currency translation | Foreign currency translation The Company’s reporting currency is the Canadian dollar. The Company’s U.S. operations are determined to have the U.S. dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. The financial statements of these operations are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment. |
Income taxes | Income taxes Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Income tax credits are treated as a reduction to current income tax expense in the year the credit arises or future periods to the extent that realization of such benefit is more likely than not. 1. Significant accounting policies (continued) (t) Income taxes (continued) The organizational structure of APUC and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. |
Financial instruments and derivatives | Financial instruments and derivatives Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts. Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument. The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities in the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk exposure, interest risk and price risk exposure associated with sales of generated electricity. For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized in OCI. The ineffective portion is immediately recognized in earnings. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings. Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings. The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption. |
Fair value measurements | Fair value measurements The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels: • Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. • Level 2 Inputs: Other than quoted prices included in Level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. |
Commitments and contingencies | Commitments and contingencies Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. |
Use of estimates | Use of estimates The preparation of financial statements requires management 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 these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and, the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount. |
Recently adopted accounting pronouncements | Recently adopted accounting pronouncements The FASB issued ASU 2015-17 Income Taxes (Topic 740) to simplify the presentation of deferred income taxes. This ASU requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this ASU. The Company retrospectively adopted this ASU in the fourth quarter of 2015. As a result, a deferred tax asset and a deferred tax liability of $7,210 and $ 3,702 , respectively, that were presented as current as of December 31, 2014 have been reclassified to non-current deferred tax asset and deferred tax liability on the consolidated balance sheets. The FASB issued ASU 2015-13 Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets. This ASU clarifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. The adoption of this ASU in the third quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-10, Technical Corrections and Improvements, to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification. The adoption of this ASU in the second quarter of 2015 had no impact on the Company’s consolidated financial statements. The FASB issued ASU 2015-04, Compensation: Retirement Benefits (Subtopic 715), to provide a practical expedient that permits an entity with a fiscal year-end that does not coincide with a month-end and an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations to measure defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end or significant event. The Company adopted this ASU prospectively in the second quarter of 2015 and as a result, remeasured amendments to its pension plans, made during the second quarter, using the month-end closest to the amendments. The FASB issued ASU 2015-03, Interest: Imputation of Interest (Subtopic 835-30), to simplify presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected. Effective January 1, 2015, the Company applied this ASU retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt. In accordance with ASU 2015-15 Interest: Imputation of Interest (Subtopic 835-30), the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments as other assets. The FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This newly issued accounting standard raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Effective January 1, 2015, the Company adopted this ASU prospectively and as a result, its adoption had no impact on discontinued operations reported in prior periods. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged . The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard. The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations. |
Recent accounting guidance not yet adopted | Recently issued accounting guidance not yet adopted The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged . The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard. The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations. The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations. |
Significant accounting polici36
Significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Capitalization of Interest | 2015 2014 Interest capitalized on non-regulated property $ 1,189 $ 3,584 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,657 1,577 Allowance for equity funds 2,425 1,910 Total $ 5,271 $ 7,071 |
Estimated Useful Lives of Depreciable Assets | The ranges of estimated useful lives and the weighted average useful lives are summarized below: Range of useful lives Weighted average useful lives 2015 2014 2015 2014 Generation Group 3 - 60 3 - 60 32 35 Distribution Group 5 - 100 5 - 100 42 40 Equipment 5 - 50 5 - 50 14 14 |
Business acquisitions and dev37
Business acquisitions and development projects (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Schedule of Acquisition of Noncontrolling Interest | As a result of the transaction, the Generation Group now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units resulting in the elimination of the non-controlling interest in respect of the Class B partnership units of Wind Portfolio SponsorCo as follows: Elimination of non-controlling interest in Class B partnership units $ 205,796 Non-controlling interest portion of currency translation adjustment recorded to AOCI (21,029 ) Non-controlling interest portion of unrealized gain on cash flow hedges recorded to AOCI (2,543 ) Decrease in deferred income tax asset (32,551 ) Additional paid-in capital (22,552 ) Cash $ 127,121 |
Property, plant and equipment (
Property, plant and equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment consist of the following: 2015 Cost Accumulated depreciation Net book value Generation $ 2,138,748 $ 358,200 $ 1,780,548 Distribution 2,075,059 265,741 1,809,318 Land 23,258 — 23,258 Equipment and other 129,555 37,443 92,112 Construction in progress Generation 64,779 — 64,779 Distribution 103,669 — 103,669 $ 4,535,068 $ 661,384 $ 3,873,684 5. Property, plant and equipment (continued) 2014 Cost Accumulated Net book Generation $ 1,827,247 $ 270,746 $ 1,556,501 Distribution 1,555,289 147,726 1,407,563 Land 19,347 — 19,347 Equipment and other 119,367 29,526 89,841 Construction in progress Generation 82,840 — 82,840 Distribution 122,330 — 122,330 $ 3,726,420 $ 447,998 $ 3,278,422 |
Intangible assets and goodwill
Intangible assets and goodwill (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | Intangible assets consist of the following: 2015 Cost Accumulated amortization Net book value Power sales contracts $ 78,725 $ 40,244 $ 38,481 Customer relationships 37,083 10,371 26,712 Interconnection agreements 13,000 230 12,770 $ 128,808 $ 50,845 $ 77,963 2014 Cost Accumulated Net book Power sales contracts $ 64,605 $ 33,704 $ 30,901 Customer relationships 31,094 7,984 23,110 Interconnection agreements — — — — $ 95,699 $ 41,688 $ 54,011 |
Goodwill | Changes in goodwill are as follows: Distribution Group Balance, January 1, 2014 $ 84,647 Foreign exchange 7,681 Balance, December 31, 2014 $ 92,328 Business acquisitions 290 Foreign exchange 17,875 Balance, December 31, 2015 $ 110,493 |
Regulatory matters (Tables)
Regulatory matters (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | Regulatory assets and liabilities consist of the following: 2015 2014 Regulatory assets Environmental remediation (a) $ 116,747 $ 102,735 Pension and post-employment benefits (b) 69,537 63,512 Commodity costs adjustment (c) 7,643 41,502 Rate case costs (d) 6,535 4,161 Rate adjustment mechanism (e) 14,804 6,207 Other 30,049 29,155 Total regulatory assets $ 245,315 $ 247,272 Less current regulatory assets (32,213 ) (61,645 ) Non-current regulatory assets $ 213,102 $ 185,627 Regulatory liabilities Cost of removal (f) $ 107,988 $ 78,013 Rate-base offset (g) 24,984 23,427 Commodity costs adjustment (c) 32,423 10,389 Other 9,952 9,927 Total regulatory liabilities $ 175,347 $ 121,756 Less current regulatory liabilities (44,167 ) (20,590 ) Non-current regulatory liabilities $ 131,180 $ 101,166 (a) Environmental remediation Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 13(b)) are recovered through rates over a period of 7 years and are subject to an annual cap. (b) Pension and post-employment benefits As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. An amount of $32,313 relates to a recent acquisition and was authorized for recognition as an asset by the regulator. Recovery is anticipated to be approved in a final rate order to be received on completion of the next general rate case. The balance is recovered through rates over the future services years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712 Compensation Non-retirement Post-employment Benefits and ASC 715 Compensation Retirement Benefits before the transfer to regulatory asset occurred. (c) Commodity costs adjustment The revenue of the electric and natural gas utilities includes a component which is designed to recover the cost of electricity or natural gas through rates charged to customers. Under deferred energy accounting, to the extent actual natural gas and purchased power costs differ from natural gas and purchased power costs recoverable through current rates, that difference is not recorded on the consolidated statements of operations but rather is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of natural gas or electricity in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment. 7. Regulatory matters (continued) (d) Rate case costs The costs to file, prosecute and defend rate case applications are referred to as rate case costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Peach State Gas System and New England Gas Systems are subject to a revenue decoupling mechanism approved by their respective regulator which require charging approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but collected over a period not exceeding 24 months is accrued upon approval of the Final Order. (f) Cost of removal The regulatory liability for cost of removal represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire the utility plant. (g) Rate-base offset The regulators imposed a rate-base offset that would reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of ten years. |
Long-term investments (Tables)
Long-term investments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Long Term Investments And Notes Receivable [Abstract] | |
Long-term Investments | Long-term investments consist of the following: 2015 2014 Equity-method investees 50% interest in Odell Wind Project Joint Venture (a) $ 42,287 $ 2,267 50% interest in Deerfield Wind Project Joint Venture (b) 2,240 — Interests in natural gas pipeline developments (c) 5,623 1,063 Other 2,323 3,268 $ 52,473 $ 6,598 Available-for-sale investment $ 2,946 $ 137 Notes receivable Development loans (d) $ 96,924 $ 17,582 Red Lily Senior loan Tranche 2, interest at 6.31% (e) 11,588 11,588 Red Lily Subordinated loan Tranche 1, interest at 12.5% (e) 6,565 6,565 Other 4,306 3,775 119,383 39,510 Total long-term investments 174,802 46,245 Less current portion — (2,966 ) Total long-term investments $ 174,802 $ 43,279 8. Long-term investments (continued) (a) Odell Wind Project Joint Venture On November 14, 2014, the Company acquired a 50% equity interest in Odell SponsorCo LLC (“Odell SponsorCo”), which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Project”) in the state of Minnesota. The total construction costs of the Odell Wind Project are estimated to be U.S. $322,766 . The two members each contributed U.S. $1,000 to the capital of Odell SponsorCo on acquisition and another U.S. $23,800 on October 6, 2015. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments, within 30 days of commencement of operations, which is expected in 2016. The interest capitalized during the year to the investment while the Odell Wind Project is under construction amounts to $4,415 (2014 - nil ). As of December 31, 2015, Odell SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Odell SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $190,840 as of December 31, 2015. (b) Deerfield Wind Project Joint Venture On October 19, 2015, the Company acquired a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan. The total construction costs of the Deerfield Wind Project are estimated to be U.S. $303,000 . Upon the acquisition of the Deerfield Wind Project by Deerfield SponsorCo, the two members each contributed U.S. $1,000 to the capital of Deerfield SponsorCo. Upon execution of third-party construction loan and tax equity documents expected in 2016, each party will contribute another U.S. $18,596 plus accrued interest at 7% to the capital of Deerfield SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments at any time prior to the date that is 90 days following commencement of operations, which is expected in late 2016. The interest capitalized during the year to the investment while the Deerfield Wind Project is under construction amounts to $94 . As of December 31, 2015, Deerfield SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Deerfield SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $321,472 as of December 31, 2015. (c) Natural gas pipeline developments In December 2015, APUC acquired a 4.0% interest in Northeast Supply Pipeline LLC with an option to increase its participation to 10% . Northeast Supply LLC is a new entity undertaking the development, construction and ownership of natural gas transmission pipeline to be constructed between the Bradford and Susquehanna counties in Pennsylvania and Wright, NY. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 4.0% in a limited liability corporation together with the option to increase its participation to 10% provide significant influence. As such, the interest is accounted as an equity method investment. 8. Long-term investments (continued) (c) Natural gas pipeline developments (continued) In November 2014, APUC acquired a 2.5% interest in Northeast Expansion LLC with an option to increase its participation to 10% . Northeast Expansion LLC is a new entity undertaking the development, construction and ownership of a natural gas transmission pipeline to be constructed between Wright, NY and Dracut, MA. The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 2.5% in a limited liability corporation together with the option to increase its participation to 10% and the commitment from its New Hampshire subsidiary to a firm gas transportation agreement for service on the pipeline facilities provide significant influence. As such, the interest is accounted as an equity method investment. The total capital investment assuming the Company exercises its right to subscribe for 10% of each pipeline is estimated to be U.S. $520,000 . As of December 31, 2015, APUC had invested U.S. $4,063 (2014 - U.S. $375 ) in the pipeline projects. (d) Development loans The Company entered into a committed loan and credit support facility with Odell SponsorCo and Deerfield SponsorCo (collectively, the “Joint Ventures”). During construction, the Company is obligated to provide Joint Ventures with cash advances and credit support (in the form of letters of credit, escrowed cash, or guarantees) in amounts necessary for the continued development and construction of the Joint Ventures’ Wind Projects. The loan bears interest at an annual rate of 7% - 8% on outstanding principal amount until commercial operation date and 5% thereafter until maturity date, and the letters of credit are charged an annual fee of 2% on their stated amount. Any loan outstanding to Joint Ventures, to the extent not otherwise repaid earlier, is repayable in cash within 30 days of the fifth anniversary of the commercial operation date. As of December 31, 2015, the Company had outstanding loans of U.S. $62,751 from Odell SponsorCo and U.S. $7,281 from Deerfield SponsorCo for development costs of the Joint Ventures’ Wind Projects. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures. As of December 31, 2015, the following credit support was issued by the Company: a U.S. $15,000 letter of credit on behalf of the Odell Wind Project, to the utility under the PPA; a U.S. $1,119 letter of credit on behalf of the the Odell Wind Project pursuant to the generator interconnection agreement; guarantee of the obligations of the Joint Ventures under the wind turbine supply agreements; guarantee of the obligations of the Deerfield Wind Project under the power purchase agreement and decommissioning plan; and, a U.S. $43,238 letter of credit and guarantee of the obligations of Deerfield SponsorCo, to the vendor under the membership interest purchase and contribution agreement. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at U.S. $1,147 using a probability weighted discounted cash flow (level 3). (e) Red Lily I The Red Lily I Partnership (the “Partnership”) is owned by an independent investor. APUC provides operation and supervision services to the Red Lily I project, a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company’s investment in Red Lily I is in the form of participation in a portion of the senior and subordinated debt facilities to the Partnership. The senior debt facility consists of two tranches. A third-party lender advanced $27,000 of senior debt to the Partnership as Tranche 1. In 2011, APUC advanced $13,000 of senior debt as Tranche 2 to the Partnership and received a pre-payment of $1,412 in 2012. The third-party lender has also advanced $4,000 of senior debt Tranche 2 to the Partnership. The Company’s senior loan Tranche 2 to the Partnership earned interest at the rate of 6.31% and was replaced by subordinated debt Tranche 2 on February 23, 2016 as described below. Both tranches of senior debt are secured by substantially all the assets of the Partnership on a pari passu basis. The subordinated loan earns an interest rate of 12.5% , and the principal matures in 2036 but is repayable by the Partnership in whole or in part at any time after 2016 , without a pre-payment premium. The subordinated loan is secured by substantially all the assets of the Partnership but is subordinated to the senior debt. 8. Long-term investments (continued) (e) Red Lily I (continued) Subsequent to year-end, on February 23, 2016, a second tranche of subordinated loan for an amount equal to $15,588 was advanced by the Company. The proceeds from this additional subordinated debt were used by Red Lily I to repay Tranche 2 of the Partnership’s senior debt, including the Company’s portion. In connection with the subordinated debt facility, the Company has an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its Tranche 1 and Tranche 2 subordinated loans, exercisable for a period of 90 days commencing on February 24, 2016. |
Long-term debt (Tables)
Long-term debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long Term Liabilities | Long-term debt consists of the following: 2015 2014 Generation Group $350,000 revolving credit facility, interest rate is equal to bankers’ acceptance or LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is BA or LIBOR plus 1.45%, maturing July 31, 2019. $ 27,300 $ 23,400 Algonquin Power Co.: 481,991 481,438 Shady Oaks Wind Facility: U.S.$76,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points. This facility was repaid in May 2015. — 88,168 Long Sault Hydro Facility: Senior Debt: $34,760 bonds bearing an interest rate of 10.21%, maturing December 31, 2027. The bonds have interest and principal payments, payable monthly in arrears. 34,760 35,997 Chuteford Hydro Facility: Senior Debt: $2,587 bonds bearing an interest rate of 11.55%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears. 2,587 3,022 Distribution Group U.S.$200,000 revolving credit facility, interest rate is equal to LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is LIBOR plus 1.25%, maturing September 30, 2018. — 23,898 Liberty Utilities Co.: U.S.$ 50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S.$ 25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S.$115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S.$ 15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S.$ 75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; U.S.$ 60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S.$ 25,000, bearing an interest rate of 4.26%, maturing July 31, 2028; U.S.$ 90,000, bearing an interest rate of 4.13%, maturing April 30, 2045; U.S.$ 70,000, bearing an interest rate of 4.13%, maturing July 15, 2045. The notes have interest only payments, payable semi-annually. 721,581 419,876 2015 2014 Calpeco Electric System: U.S.$45,000 bearing an interest rate of 5.19%, maturing December 29, 2020; U.S.$25,000 bearing an interest rate of 5.59%, maturing December 29, 2025. The notes have interest only payments, payable semi-annually in arrears. 96,015 80,368 Liberty Water Co: Senior Unsecured Notes: U.S.$50,000 bearing an interest rate of 5.60% $5,000 matures annually beginning June 20, 2016; $25,000 maturing December 22, 2020. The note bears interest payments semi-annually in arrears. 68,488 57,301 New England Gas System: U.S.$6,500, bearing an interest rate of 9.44%, maturing February 15, 2020; U.S.$7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; U.S.$6,000, bearing an interest rate of 7.24%, maturing December 15, 2027. The notes have interest only payments, payable semi-annually in arrears. 32,130 27,288 Granite State Electric System: Senior Unsecured Notes: U.S.$5,000, bearing an interest rate of 7.37%, maturing November 1, 2023; U.S.$5,000, bearing an interest rate of 7.94%, maturing July 1, 2025; U.S.$5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually. 20,730 17,373 LPSCo Water System: 1999 and 2001 IDA bonds bearing interest rates of 5.85% and 6.71%. This facility was repaid in October 2015. — 12,441 Bella Vista Water System: U.S.$877 Water Infrastructure Financing Authority of Arizona loans bearing interest rates of 6.26% and 6.10%, and maturing March 1, 2020 and December 1, 2017, respectively. The loans have principal and interest payments, payable monthly and quarterly in arrears. 1,213 1,149 $ 1,486,795 $ 1,271,719 Less: current portion (8,945 ) (9,130 ) $ 1,477,850 $ 1,262,589 |
Principal Payments | Principal payments due in the next five years and thereafter are as follows: 2016 2017 2018 2019 2020 Thereafter Total Generation Group $ 1,816 $ 2,045 $ 137,272 $ 30,152 $ 2,641 $ 375,415 $ 549,341 Distribution Group 7,129 76,358 7,135 7,149 147,640 701,371 946,782 Total $ 8,945 $ 78,403 $ 144,407 $ 37,301 $ 150,281 $ 1,076,786 $ 1,496,123 |
Pension and other post-retire43
Pension and other post-retirement benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Obligations Fair Value of Plan Assets and Funded Status | The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31: Pension benefits OPEB 2015 2014 2015 2014 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 241,963 $ 178,113 $ 68,257 $ 45,399 Projected benefit obligation assumed from business combination — 1,022 — — Modifications to pension plan (4,995 ) (560 ) — — Service cost 6,663 4,828 3,093 2,022 Interest cost 9,642 8,549 2,914 2,186 Actuarial loss (gain) (16,098 ) 39,704 (8,466 ) 14,893 Contributions from retirees — — 412 331 Benefits paid (13,024 ) (8,125 ) (2,447 ) (1,586 ) Loss on foreign exchange 45,231 18,432 12,802 5,012 Projected benefit obligation, end of year $ 269,382 $ 241,963 $ 76,565 $ 68,257 Change in plan assets Fair value of plan assets, beginning of year 156,990 139,280 14,295 13,395 Actual return (loss) on plan assets (5,657 ) 6,568 20 1,176 Employer contributions 7,975 5,676 3,028 (222 ) Benefits paid (12,589 ) (7,414 ) (2,036 ) (1,255 ) Gain on foreign exchange 29,453 12,880 2,842 1,201 Fair value of plan assets, end of year $ 176,172 $ 156,990 $ 18,149 $ 14,295 Unfunded status $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) Amounts recognized in the consolidated balance sheets consists of: Current liabilities (470 ) — (1,062 ) (333 ) Non-current liabilities (92,740 ) (84,973 ) (57,354 ) (53,629 ) Net amount recognized $ (93,210 ) $ (84,973 ) $ (58,416 ) $ (53,962 ) |
Amounts Recognized in Accumulated Other Comprehensive loss | The amounts recognized in OCI before tax were as follows: AOCI Pension OPEB Balance, January 1, 2014 $ (14,385 ) $ (9,083 ) Current year net actuarial gain 43,350 14,338 Current year prior service loss (563 ) — Amortization of net actuarial loss 349 641 Balance at December 31, 2014 $ 28,751 $ 5,896 Current year net actuarial loss 1,505 (7,554 ) Current year prior service credits (4,864 ) — Amortization of net actuarial gain (1,358 ) (680 ) Amortization of prior service credits 457 — Balance at December 31, 2015 $ 24,491 $ (2,338 ) |
Weighted Average Assumptions Used to Determine Net Benefit Obligation | Weighted average assumptions used to determine net benefit obligation for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 4.16 % 3.71 % 4.23 % 3.80 % Rate of compensation increase 3.00 % 3.01 % N/A N/A Health care cost trend rate Before Age 65 6.50 % 7.00 % Age 65 and after 6.50 % 7.00 % Assumed Ultimate Medical Inflation Rate 4.75 % 5.00 % Year in which Ultimate Rate is reached 2023 2019 Weighted average assumptions used to determine net benefit cost for 2015 and 2014 were as follows: Pension benefits OPEB 2015 2014 2015 2014 Discount rate 3.71 % 4.55 % 3.82 % 4.60 % Expected return on assets 6.44 % 7.00 % 5.50 % 5.53 % Rate of compensation increase 3.01 % 2.97 % N/A N/A Health care cost trend rate Before Age 65 7.00 % 7.63 % Age 65 and after 7.00 % 7.63 % Assumed Ultimate Medical Inflation Rate 5.00 % 5.00 % Year in which Ultimate Rate is reached 2019 2019 |
Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR) | The effect of a one percent change in the assumed health care cost trend rate (“HCCTR”) for 2015 is as follows: 2015 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 10,763 Total service and interest cost 1,111 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (8,687 ) Total service and interest cost (871 ) |
Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses | The following table lists the components of net benefit costs for the pension plans and OPEB recorded as part of operating expenses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition. Pension benefits OPEB 2015 2014 2015 2014 Service cost $ 6,663 $ 4,828 $ 3,093 $ 2,022 Interest cost 9,642 8,549 2,914 2,186 Expected return on plan assets (11,989 ) (10,018 ) (713 ) (628 ) Amortization of net actuarial loss (gain) 1,398 (346 ) 510 (641 ) Amortization of prior service credits (471 ) — — — Net benefit cost $ 5,243 $ 3,013 $ 5,804 $ 2,939 |
Target Asset Allocation | The Company’s target asset allocation is as follows: Asset Class Target (%) Range (%) Equity securities 74 % 49% - 78% Debt securities 26 % 22% - 51% Other — % 0% - 1% 10. Pension and other post-employment benefits (continued) (d) Plan assets (continued) The fair values of investments as of December 31, 2015, by asset category, are as follows: Asset Class Level 1 Percentage Equity securities 138,993 72 % Debt securities 54,542 28 % Other 787 — % |
Expected Benefit Payments | The expected benefit payments over the next ten years are as follows: 2016 2017 2018 2019 2020 2021-2025 Pension plan $ 15,037 $ 13,829 $ 14,474 $ 15,120 $ 15,692 $ 88,692 OPEB 3,113 3,375 3,584 3,804 4,396 25,720 |
Mandatorily redeemable Series44
Mandatorily redeemable Series C preferred shares (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Schedule of Dividend and Redemption Payments | Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are: 2016 $ 979 2017 908 2018 1,068 2019 1,282 2020 1,344 Thereafter to 2031 18,516 Redemption amount 5,340 29,437 Less amounts representing interest (10,910 ) 18,527 Less current portion (979 ) $ 17,548 |
Other assets (Tables)
Other assets (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | Other assets consist of the following: 2015 2014 Restricted cash $ 18,999 $ 18,702 Deferred financing costs 3,211 2,428 Other 4,770 4,475 26,980 25,605 Less current portion (464 ) — $ 26,516 $ 25,605 |
Other long-term liabilities a46
Other long-term liabilities and deferred credits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Liabilities Disclosure [Abstract] | |
Other Long Term Liabilities | Other long-term liabilities consist of the following: 2015 2014 Advances in aid of construction (a) $ 92,285 $ 81,104 Environmental remediation obligation (b) 71,529 70,072 Asset retirement obligations (c) 17,799 13,884 Customer deposits (d) 15,074 11,713 Deferred income (e) 13,682 13,132 Deferred credits (f) 24,110 19,130 Other 25,277 17,503 259,756 226,538 Less current portion (36,621 ) (49,303 ) $ 223,135 $ 177,235 (a) Advances in aid of construction The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development. In many instances, developer advances can be subject to refund but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 10 to 20 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2015, $4,637 (2014 - $4,608 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation Prior to their acquisition by the Company, EnergyNorth Gas, Granite State Electric and New England Gas Systems were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites. The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $78,495 (2014 - $72,594 ) which at discount rates ranging from 2.5% to 4.2% represents the recorded accrual of $71,529 as of December 31, 2015 (2014 - $70,072 ). Approximately $46,929 is expected to be incurred over the next three years with the balance of cash flows to be incurred over the following 29 years. 13. Other long-term liabilities and deferred credits (continued) (b) Environmental remediation obligation (continued) Changes in the environmental remediation obligation are as follows: 2015 2014 Opening Balance $ 70,072 $ 69,555 Remediation activities (10,621 ) (12,739 ) Accretion 2,147 2,273 Changes in cash flow estimates 3,171 268 Revision in assumptions (5,843 ) 1,954 Purchase price adjustment — 2,726 Foreign exchange rate adjustment 12,603 6,035 Closing Balance $ 71,529 $ 70,072 By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2015, the Company has reflected a regulatory asset of $116,747 (2014 - $102,735 ) for the MGP and related sites (note 7(a)). (c) Asset retirement obligations Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and PCB contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities. During the year, APUC recorded additional asset retirement obligations of $ 506 (2014 - $ 2,570 ) for renewable generation facilities being constructed and accretion expense of $854 (2014 - $527 ). (d) Customer deposits Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement. (e) Deferred income Proceeds received from insurance in advance of repairs, rates collected subject to dispute and other similar proceeds are deferred until they are virtually certain of being realized. |
Changes in Environmental Remediation Obligation | Changes in the environmental remediation obligation are as follows: 2015 2014 Opening Balance $ 70,072 $ 69,555 Remediation activities (10,621 ) (12,739 ) Accretion 2,147 2,273 Changes in cash flow estimates 3,171 268 Revision in assumptions (5,843 ) 1,954 Purchase price adjustment — 2,726 Foreign exchange rate adjustment 12,603 6,035 Closing Balance $ 71,529 $ 70,072 |
Shareholders' capital (Tables)
Shareholders' capital (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Schedule of Shares Issued and Outstanding | The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2015 and 2014: Preferred shares Number of shares Price per share Carrying amount Series A 4,800,000 $ 25 $ 116,546 Series D 4,000,000 $ 25 97,259 $ 213,805 |
Number of Common Shares | Number of common shares: 2015 2014 Common shares, beginning of year 238,149,468 206,348,985 Public offering (i) 14,355,000 29,444,000 Issuance of shares under the dividend reinvestment (iv) and employee share purchase plans ((c)(ii)) 3,364,951 2,356,483 Common shares, end of year 255,869,419 238,149,468 |
Share-Based Compensation Expense | For the year ended December 31, 2015 , APUC recorded $5,330 (2014 - $3,248 ) in total share-based compensation expense detailed as follows: 2015 2014 Share options $ 2,742 $ 1,931 Directors deferred share units 404 273 Employee share purchase 158 116 Performance share units 2,026 928 Total share-based compensation $ 5,330 $ 3,248 |
Fair Value of Share Options Granted | The following assumptions were used in determining the fair value of share options granted: 2015 2014 Risk-free interest rate 1.3 % 2.0 % Expected volatility 38 % 38 % Expected dividend yield 4.0 % 3.8 % Expected life 8 years 8 years Weighted average grant date fair value per option $ 2.45 $ 2.00 |
Stock Option Activity | Share option activity during the years is as follows: Number of awards Weighted average exercise price Weighted average remaining contractual term (years) Aggregate intrinsic value Balance at January 1, 2014 4,567,129 $ 5.70 5.45 $ 7,814 Granted 969,998 7.95 8.00 — Balance at December 31, 2014 5,537,127 $ 6.09 4.96 $ 19,648 Granted 1,627,525 9.75 8.00 — Balance at December 31, 2015 7,164,652 $ 6.92 4.74 $ 28,561 Exercisable at December 31, 2015 4,618,323 $ 5.74 3.55 $ 23,898 |
Performance Stock Units | A summary of the PSUs follows: Number of awards Weighted average grant-date fair value Weighted average remaining contractual term (years) Aggregate intrinsic value Balance at January 1, 2014 66,195 $ 6.57 0.62 $ 486 Granted 407,962 8.22 3.00 3,333 Exercised (22,665 ) 6.13 — (185 ) Forfeited (11,406 ) 8.22 — (93 ) Balance at December 31, 2014 440,086 $ 6.57 1.81 $ 4,242 Granted, including dividends 212,250 9.72 2.62 — Exercised (41,131 ) 6.86 — 381 Forfeited (47,089 ) 8.30 — — Balance at December 31, 2015 564,116 $ 7.59 1.63 $ 6,155 Exercisable at December 31, 2015 157,972 $ 8.22 — $ 1,723 |
Accumulated other comprehensi48
Accumulated other comprehensive income (loss) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Accumulated other comprehensive income (loss) | AOCI consists of the following balances, net of tax: Foreign currency cumulative translation Unrealized gain on cash flow hedges Net change on available-for-sale investments Pension and post-employment actuarial changes Total Balance, January 1, 2014 $ (57,471 ) $ 11,840 $ — $ 14,221 $ (31,410 ) OCI (loss) before reclassifications 68,938 3,358 519 (35,396 ) 37,419 Amounts reclassified — 5,423 (518 ) (273 ) 4,632 Net current period OCI 68,938 8,781 1 (35,669 ) 42,051 Acquisition of non-controlling interest 21,029 2,543 — — 23,572 Balance, December 31, 2014 $ 32,496 $ 23,164 $ 1 $ (21,448 ) $ 34,213 OCI before reclassifications 228,861 21,896 (73 ) 6,487 257,171 Amounts reclassified — (5,731 ) — 1,084 (4,647 ) Net current period OCI $ 228,861 $ 16,165 $ (73 ) $ 7,571 $ 252,524 Balance, December 31, 2015 $ 261,357 $ 39,329 $ (72 ) $ (13,877 ) $ 286,737 |
Dividends (Tables)
Dividends (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Cash Dividends [Abstract] | |
Dividends | Dividends declared in Canadian equivalent dollars during the year were as follows: 2015 2014 Dividend Dividend per share Dividend Dividend per share Common shares $ 124,831 $ 0.4867 $ 83,097 $ 0.3695 Series A preferred shares $ 5,400 $ 1.1250 $ 5,400 $ 1.1250 Series D preferred shares $ 5,000 $ 1.2500 $ 4,103 $ 1.0257 |
Non-controlling Interests (Tabl
Non-controlling Interests (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Noncontrolling Interest [Abstract] | |
Net Earnings (Loss) Attributable to Noncontrolling Interests | Net loss attributable to non-controlling interests consists of the following: 2015 2014 Net earnings attributable to Class B partnership units of Wind Portfolio SponsorCo (i) $ — $ 3,484 Net loss attributable to Class A partnership units (ii) (33,942 ) (27,199 ) Other net earnings attributable to non-controlling interests 1,966 1,529 Total net loss attributable to non-controlling interests $ (31,976 ) $ (22,186 ) (i) On March 31, 2014, the Company acquired the remaining Class B partnership units of Wind Portfolio SponsorCo from the non-controlling interest holder. As a result of the transaction, the Company now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units (note 3(h)). (ii) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Senate, Minonk and Sandy Ridge wind facilities and, beginning December 31, 2014, the Bakersfield Solar facility are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(q). |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Provision for Income Taxes | The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2014 - 26.5% ). The differences are as follows: 2015 2014 Expected income tax expense at Canadian statutory rate $ 34,516 $ 19,199 Increase (decrease) resulting from: Recognition of deferred credit (2,448 ) (5,763 ) Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (3,855 ) (1,677 ) Non-taxable corporate dividend (3,311 ) (2,618 ) Non-controlling interests share of income 12,511 8,824 Production tax credit (254 ) (339 ) Allowance for equity funds used during construction (935 ) (746 ) State taxes 733 604 Adjustment relating to prior periods 2,431 — CRA Settlement 2,709 — Other 1,616 (677 ) Income tax expense $ 43,713 $ 16,807 |
Income (Loss) Before Taxes | For the years ended December 31, 2015 and 2014, earnings from continuing operations before income taxes consist of the following: 2015 2014 Canadian operations $ 28,481 $ 11,930 U.S. operations 101,768 60,519 $ 130,249 $ 72,449 |
Income Tax Expenses (Recovery) Attributable to Income (Loss) | Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2015 Canada $ 5,272 $ 1,959 $ 7,231 United States 2,038 34,444 36,482 $ 7,310 $ 36,403 $ 43,713 Year ended December 31, 2014 Canada $ 5,660 $ (3,538 ) $ 2,122 United States (1,986 ) 16,671 14,685 $ 3,674 $ 13,133 $ 16,807 |
Tax Effect of Temporary Difference Between Assets and Liability | The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are presented below: 2015 2014 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 396,727 $ 319,056 Pension and OPEB 57,969 54,458 Acquisition-related costs 6,035 5,168 Environmental obligation 28,230 28,555 Production tax credit 3,027 2,098 Reserves not currently deductible 2,503 2,315 Other 4,970 3,988 Total deferred income tax assets 499,461 415,638 Less valuation allowance (17,478 ) (15,534 ) Total deferred tax assets 481,983 400,104 Deferred tax liabilities: Property, plant and equipment (544,616 ) (387,931 ) Intangible assets (2,760 ) (2,752 ) Outside basis in partnership (32,221 ) (15,194 ) Regulatory accounts (28,270 ) (49,399 ) Financial derivatives (31,806 ) (15,013 ) Total deferred tax liabilities (639,673 ) (470,289 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 18,109 $ 64,275 Deferred tax liabilities (175,799 ) $ (134,460 ) Net deferred tax liabilities $ (157,690 ) $ (70,185 ) |
Non Capital Losses Carry Forwards | As of December 31, 2015, the Company had non-capital losses carried forward available to reduce future year’s taxable income, which expire as follows: Year of expiry Non-capital loss carryforwards 2016 $ — 2017 and onwards 967,499 $ 967,499 |
Basic and diluted net earning52
Basic and diluted net earnings per share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share, Basic and Diluted [Abstract] | |
Reconciliation of Net Income and Weighted Average Shares Used in Computation of Basic and Diluted Earnings per Share | The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows: 2015 2014 Net earnings attributable to shareholders of APUC $ 117,480 $ 75,701 Series A Preferred shares dividend 5,400 5,400 Series D Preferred shares dividend 5,000 4,103 Net earnings attributable to common shareholders of APUC $ 107,080 $ 66,198 Discontinued operations (1,032 ) (2,127 ) Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 108,112 $ 68,325 Weighted average number of shares Basic 253,172,088 213,953,870 Effect of dilutive securities 3,344,632 2,387,722 Diluted 256,516,720 216,341,592 |
Segmented information (Tables)
Segmented information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Results of Operations and Assets for Segments | The results of operations and assets for these segments are reflected in the tables below. Year ended December 31, 2015 Generation Distribution Corporate Total Revenue $ 244,751 $ 783,104 $ — $ 1,027,855 Fuel and power purchased 27,990 348,883 — 376,873 Net revenue 216,761 434,221 — 650,982 Operating expenses 63,601 213,750 1,210 278,561 Administrative expenses 10,822 21,570 8,283 40,675 Depreciation and amortization 67,293 82,513 — 149,806 Gain on foreign exchange — — (2,631 ) (2,631 ) Operating income (loss) from continuing operations 75,045 116,388 (6,862 ) 184,571 Interest expense 29,395 34,971 1,627 65,993 Interest, dividend, equity and other income (1,154 ) (3,974 ) (3,967 ) (9,095 ) Other expenses (gain) (5,623 ) 391 2,656 (2,576 ) Earnings (loss) before income taxes $ 52,427 $ 85,000 $ (7,178 ) $ 130,249 Property, plant and equipment $ 1,895,617 $ 1,914,980 $ 63,087 $ 3,873,684 Equity-method investees 44,638 769 7,066 52,473 Total assets 2,345,905 2,532,894 112,926 4,991,725 Capital expenditures 55,992 141,445 6,758 204,195 21. Segmented information (continued) Year ended December 31, 2014 Generation Distribution Corporate Total Revenue $ 218,765 $ 722,849 $ — $ 941,614 Fuel and power purchased 39,264 381,622 — 420,886 Net revenue 179,501 341,227 — 520,728 Operating expenses 55,482 178,248 308 234,038 Administrative expenses 13,457 19,947 1,288 34,692 Depreciation and amortization 58,248 53,671 2,128 114,047 Gain on foreign exchange — — (1,112 ) (1,112 ) 52,314 89,361 (2,612 ) 139,063 Interest expense 33,868 27,139 1,411 62,418 Interest, dividend and other income (1,187 ) (3,369 ) (3,202 ) (7,758 ) Other expense (gain) 48 300 11,606 11,954 Earnings (loss) before income taxes $ 19,585 $ 65,291 $ (12,427 ) $ 72,449 Property, plant and equipment $ 1,687,465 $ 1,531,166 $ 59,791 $ 3,278,422 Equity-method investees 3,520 500 2,578 6,598 Total assets 1,896,265 2,098,244 108,339 4,102,848 Capital expenditures 201,063 176,849 54,461 432,373 |
Information on Operations by Geographic Area | Information on operations by geographic area is as follows: 2015 2014 Revenue Canada $ 86,977 $ 92,267 United States 940,878 849,347 $ 1,027,855 $ 941,614 Property, plant and equipment Canada $ 592,598 $ 590,580 United States 3,281,086 2,687,842 $ 3,873,684 $ 3,278,422 Intangible assets Canada $ 40,186 $ 25,601 United States 37,777 28,410 $ 77,963 $ 54,011 |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Estimates of Future Commitments | Detailed below are estimates of future commitments under these arrangements: Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total Power purchase (i) $ 82,403 $ 52,644 $ 55,599 $ 59,165 $ 59,791 $ — $ 309,602 Gas supply and service agreements (ii) 66,264 46,673 36,621 35,482 32,070 82,509 299,619 Service agreements 38,335 38,151 35,019 35,734 35,955 518,193 701,387 Capital projects 35,842 7,571 71 71 71 18 43,644 Operating leases 5,863 5,319 4,866 4,754 4,793 106,210 131,805 Total $ 228,707 $ 150,358 $ 132,176 $ 135,206 $ 132,680 $ 706,930 $ 1,486,057 (i) Power purchase: APUC’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2015. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. (ii) Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power. |
Non-cash operating items (Table
Non-cash operating items (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Changes In Non Cash Operating Items [Abstract] | |
Changes in Non-Cash Operating Items | The changes in non-cash operating items consist of the following: 2015 2014 Accounts receivable $ 6,715 $ (23,640 ) Natural gas in storage 3,049 (5,942 ) Supplies and consumable inventory (2,968 ) (3,861 ) Income taxes receivable (2,529 ) (189 ) Prepaid expenses (7,833 ) 827 Accounts payable (18,261 ) 54,299 Accrued liabilities (28,495 ) 32,520 Current income tax liability 1,820 (1,527 ) Net regulatory assets and liabilities 37,353 (54,277 ) $ (11,149 ) $ (1,790 ) |
Financial instruments (Tables)
Financial instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | Fair value of financial instruments 2015 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 119,383 $ 126,468 $ — $ 126,468 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 88,357 88,357 — — 88,357 Commodity contracts for regulated operations 4 4 — 4 — Total derivative financial instruments 88,361 88,361 — 4 88,357 Total financial assets $ 207,744 $ 214,829 $ — $ 126,472 $ 88,357 Long-term debt $ 1,486,795 $ 1,547,346 $ 511,829 $ 1,035,517 $ — Preferred shares, Series C 18,527 17,303 — 17,303 — Derivative financial instruments: Energy contracts designated as a cash flow hedge 446 446 — — 446 Cross-currency swap designated as a net investment hedge 101,559 101,559 — 101,559 — Interest rate swap designated as a hedge 9,659 9,659 — 9,659 — Currency forward contract not designated as a hedge 1,918 1,918 — 1,918 — Commodity contracts for regulated operations 1,676 1,676 — 1,676 — Total derivative financial instruments 115,258 115,258 — 114,812 446 Total financial liabilities $ 1,620,580 $ 1,679,907 $ 511,829 $ 1,167,632 $ 446 24. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2014 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 39,510 $ 41,339 $ — $ 41,339 $ — Derivative financial instruments: Energy contracts designated as a cash flow hedge 41,966 41,966 — — 41,966 Energy contracts not designated as a cash flow hedge 504 504 — — 504 Total derivative financial instruments 42,470 42,470 — — 42,470 Total financial assets $ 81,980 $ 83,809 $ — $ 41,339 $ 42,470 Long-term debt $ 1,271,719 $ 1,363,934 $ 520,142 $ 843,792 $ — Preferred shares, Series C 18,693 18,209 — 18,209 — Derivative financial instruments: Cross-currency swap designated as a net investment hedge 36,276 36,276 — 36,276 — Interest rate swaps designated as a hedge 4,684 4,684 — 4,684 — Interest rate swaps not designated as a hedge 1,383 1,383 — 1,383 — Commodity contracts for regulated operations 2,928 2,928 — 2,928 — Total derivative financial instruments 45,271 45,271 — 45,271 — Total financial liabilities $ 1,335,683 $ 1,427,414 $ 520,142 $ 907,272 $ — |
Summary of Commodity Volumes Associated with Derivative Contracts | The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts: 2015 Financial contracts: Gas swaps 1,086,228 Gas options 412,369 1,498,597 |
Impact of Change in Fair Value of Natural Gas Derivative Contracts | The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 2015 2014 Regulatory assets: Gas swap contracts U.S. $ 1,058 U.S. $ 2,178 Gas option contracts U.S. $ 154 U.S. $ 346 Regulatory liabilities: Gas swap contracts U.S. $ 3 U.S. $ — Gas option contracts U.S. $ — U.S. $ — |
Long-Term Energy Derivative Contracts | The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities and at one of its hydro facilities no longer subject to a power purchase agreement by entering into the following long-term energy derivative contracts. Notional quantity (MW-hrs) Expiry Receive average prices (per MW-hr) Pay floating price (per MW-hr) 49,135 December 2016 $ 68.56 AESO 801,098 December 2022 U.S. $ 42.81 PJM Western HUB 3,419,634 December 2022 U.S. $ 30.25 NI HUB 3,997,509 December 2027 U.S. $ 36.46 ERCOT North HUB |
Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Consolidated Statement of Operations | The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2015 2014 Effective portion of cash flow hedge, loss (gain) $ 21,932 $ (2,592 ) Amortization of cash flow hedge (36 ) (32 ) Loss (gain) reclassified from AOCI (5,731 ) 5,423 $ 16,165 $ 2,799 Less non-controlling interest — 5,982 OCI attributable to shareholders of APUC $ 16,165 $ 8,781 |
Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges | The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2015 2014 Change in unrealized loss (gain) on derivative financial instruments: Interest rate swaps $ (1,383 ) $ (1,797 ) Energy derivative contracts 886 3,386 Currency forward contract 1,918 — Total change in unrealized loss (gain) on derivative financial instruments $ 1,421 $ 1,589 Realized loss (gain) on derivative financial instruments: Interest rate swaps 1,498 1,962 Energy derivative contracts (579 ) (3,627 ) Total realized loss (gain) on derivative financial instruments $ 919 $ (1,665 ) Loss (gain) on derivative financial instruments not accounted for as hedges 2,340 (76 ) Ineffective portion of derivative financial instruments accounted for as hedges (2,610 ) 1,451 $ (270 ) $ 1,375 Amounts recognized in the consolidated statements of operations consist of: Loss (gain) on derivative financial instruments $ (2,188 ) $ 1,375 Loss on foreign exchange $ 1,918 $ — $ (270 ) $ 1,375 |
Maximum Credit Risk Exposure for Financial Instruments | As of December 31, 2015, the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2015 Canadian $ US $ Cash and cash equivalents and restricted cash $ 39,972 $ 74,696 Accounts receivable 15,016 129,791 Allowance for doubtful accounts (5,756 ) Notes receivable 19,664 72,052 $ 74,652 $ 270,783 |
Liabilities Maturity Profile | The Company’s liabilities mature as follows: Due less than 1 year Due 2 to 3 years Due 4 to 5 years Due after 5 years Total Long-term debt obligations $ 8,945 $ 222,810 $ 187,582 $ 1,076,786 $ 1,496,123 Advances in aid of construction 1,347 — — 90,938 92,285 Interest on long-term debt 74,324 138,841 117,328 333,606 664,099 Purchase obligations 243,748 — — — 243,748 Environmental obligation 5,435 41,494 1,753 29,813 78,495 Derivative financial instruments: Cross-currency swap 4,828 8,963 7,508 80,260 101,559 Interest rate swaps — 9,659 — — 9,659 Currency forward 1,918 — — — 1,918 Energy derivative and commodity contracts 1,885 237 — — 2,122 Other obligations 12,808 — — 40,694 53,502 Total obligations $ 355,238 $ 422,004 $ 314,171 $ 1,652,097 $ 2,743,510 |
Significant accounting polici57
Significant accounting policies - Additional Information (Detail) CAD in Thousands | 12 Months Ended | ||
Dec. 31, 2015CADFacility | Dec. 31, 2015CAD$ / shares | Dec. 31, 2014CAD | |
Significant Accounting Policies [Line Items] | |||
Deprecation expense, reduction | CAD 3,418 | ||
Earnings per share, basic and diluted, increase due to change in depreciation method (cad per share) | $ / shares | $ 0.01 | ||
Number of power generating facilities | Facility | 2 | ||
Non-regulated energy sales | CAD 222,581 | CAD 202,300 | |
Interest expense | 65,993 | 62,418 | |
Revenue from insurance claims for business interruption | 581 | 1,227 | |
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant | |||
Significant Accounting Policies [Line Items] | |||
Generating assets of Long Sault | 104,243 | $ 104,243 | 112,344 |
Long-term debt of Long Sault | 62,138 | $ 62,138 | 59,449 |
Non-regulated energy sales | 18,651 | 11,218 | |
Operating expenses and amortization | 5,645 | 3,418 | |
Interest expense | CAD 4,407 | CAD 3,820 | |
Power sales contracts | Minimum | |||
Significant Accounting Policies [Line Items] | |||
Intangible asset, useful life | 6 years | ||
Power sales contracts | Maximum | |||
Significant Accounting Policies [Line Items] | |||
Intangible asset, useful life | 25 years | ||
Interconnection agreements | |||
Significant Accounting Policies [Line Items] | |||
Intangible asset, useful life | 40 years | ||
Customer Relationships | |||
Significant Accounting Policies [Line Items] | |||
Intangible asset, useful life | 40 years |
Significant accounting polici58
Significant accounting policies - Capitalization of Interest (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Capitalization [Line Items] | ||
Total | CAD 5,271 | CAD 7,071 |
Non-regulated property | ||
Schedule of Capitalization [Line Items] | ||
Interest capitalized on non-regulated property | 1,189 | 3,584 |
Interest expense | ||
Schedule of Capitalization [Line Items] | ||
AFUDC capitalized on regulated property | 1,657 | 1,577 |
Interest, dividend and other income | ||
Schedule of Capitalization [Line Items] | ||
AFUDC capitalized on regulated property | CAD 2,425 | CAD 1,910 |
Significant accounting polici59
Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Generation | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 3 years | 3 years |
Generation | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 60 years | 60 years |
Generation | Weighted Average | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 32 years | 35 years |
Distribution | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 5 years | 5 years |
Distribution | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 100 years | 100 years |
Distribution | Weighted Average | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 42 years | 40 years |
Equipment and other | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 5 years | 5 years |
Equipment and other | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 50 years | 50 years |
Equipment and other | Weighted Average | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated useful lives | 14 years | 14 years |
Recently issued accounting pr60
Recently issued accounting pronouncements Recently issued accounting pronouncements (Details) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Deferred finance costs | CAD 3,211 | CAD 2,428 |
New Accounting Pronouncement, Early Adoption, Effect | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Deferred tax assets, net, current | (7,210) | |
Deferred tax liabilities, net, current | CAD (3,702) | |
Other Assets | New Accounting Pronouncement, Early Adoption, Effect | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Deferred finance costs | (8,304) | |
Long-term Debt | New Accounting Pronouncement, Early Adoption, Effect | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Deferred finance costs | CAD 8,304 |
Business acquisitions and dev61
Business acquisitions and development projects - Additional Information (Details) | Mar. 09, 2016CAD | Mar. 01, 2016CAD | Feb. 09, 2016CAD | Feb. 09, 2016USD ($) | Jan. 08, 2016USD ($)water_utility | Apr. 22, 2015CADMWh | Jan. 02, 2015USD ($) | Dec. 02, 2014CADMWh | May. 30, 2014USD ($)customer | Mar. 31, 2014CAD | Mar. 31, 2014USD ($) | Dec. 20, 2013CAD | Dec. 20, 2013USD ($) | Jan. 01, 2013MW | Mar. 31, 2015USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015CAD | Dec. 31, 2014CADMWac | Dec. 31, 2014USD ($)MWac | Feb. 09, 2016USD ($)$ / shares | May. 15, 2015USD ($) |
Business Acquisition [Line Items] | |||||||||||||||||||||
Property, plant and equipment | CAD 3,873,684,000 | CAD 3,278,422,000 | |||||||||||||||||||
Intangible assets | 77,963,000 | 54,011,000 | |||||||||||||||||||
Acquisition of non-controlling interest | 0 | 127,121,000 | |||||||||||||||||||
Additions to property, plant and equipment | CAD 204,195,000 | 432,373,000 | |||||||||||||||||||
New Hampshire Gas | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business combination, purchase price | $ | $ 3,161,000 | ||||||||||||||||||||
Wind Portfolio SponsorCo, LLC | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Noncontrolling interest acquired | 40.00% | 40.00% | 40.00% | ||||||||||||||||||
Acquisition of non-controlling interest | CAD 127,121,000 | $ 115,000,000 | |||||||||||||||||||
New England Gas System | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business combination, purchase price | CAD 67,010,000 | $ 62,745,000 | |||||||||||||||||||
Weighted average useful life of assets acquired | 34 years | ||||||||||||||||||||
Adjustment to total consideration transferred | $ | $ 3,108,000 | $ 2,701,000 | |||||||||||||||||||
Adjustments to property, plant, and equipment | $ | (1,190,000) | ||||||||||||||||||||
Adjustments to environmental obligation | $ | 2,467,000 | ||||||||||||||||||||
Adjustments to pension obligation | $ | 772,000 | ||||||||||||||||||||
Shady Oaks | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Adjustment to total consideration transferred | $ | $ 0 | $ 1,133,000 | |||||||||||||||||||
Project power capacity | MW | 109.5 | ||||||||||||||||||||
White Hall Water System | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business combination, purchase price | $ | $ 4,499,000 | ||||||||||||||||||||
Number of water distribution customers | customer | 1,900 | ||||||||||||||||||||
Number of wastewater treatment customers | customer | 2,400 | ||||||||||||||||||||
Subsequent Event | Empire | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business acquisition, cash paid per common share (usd per share) | $ / shares | $ 34 | ||||||||||||||||||||
Business combination, purchase price | CAD 3,400,000,000 | $ 2,400,000,000 | |||||||||||||||||||
Business combination, liabilities incurred | 1,300,000,000 | $ 900,000,000 | |||||||||||||||||||
Subsequent Event | Park Water Company | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business combination, purchase price | $ | $ 341,750,000 | ||||||||||||||||||||
Business combination, liabilities incurred | $ | $ 91,750,000 | ||||||||||||||||||||
Number of regulated water utilities | water_utility | 3 | ||||||||||||||||||||
Morse Wind Facility | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Wind power capacity | MWh | 23 | ||||||||||||||||||||
Property, plant and equipment | CAD 65,016,000 | ||||||||||||||||||||
Intangible assets | 16,709,000 | ||||||||||||||||||||
Wind generating asset investment | CAD 81,725,000 | ||||||||||||||||||||
Weighted average useful life of assets acquired | 35 years | ||||||||||||||||||||
Cornwall Solar Facility | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Business combination, purchase price | CAD 47,333,000 | ||||||||||||||||||||
Weighted average useful life of assets acquired | 33 years | 33 years | |||||||||||||||||||
Solar power capacity | MWac | 10 | 10 | |||||||||||||||||||
Additions to property, plant and equipment | CAD 40,090,000 | ||||||||||||||||||||
Payments to acquire intangible assets | CAD 7,243,000 | ||||||||||||||||||||
Bakersfield Solar Project | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Property, plant and equipment | $ | $ 57,160,000 | ||||||||||||||||||||
Solar power capacity | MWac | 20 | 20 | |||||||||||||||||||
Bakersfield Solar Project | Partnership | Tax Investor | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Partnership agreement, funded amount | $ | $ 22,438,000 | ||||||||||||||||||||
Saint-Damase | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Wind power capacity | MWh | 24 | ||||||||||||||||||||
Property, plant and equipment | CAD 64,155,000 | ||||||||||||||||||||
Weighted average useful life of assets acquired | 34 years | ||||||||||||||||||||
Class B Units | Wind Portfolio SponsorCo, LLC | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Ownership percentage | 100.00% | 100.00% | |||||||||||||||||||
Bridge Loan | Subsequent Event | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD 2,200,000,000 | $ 1,600,000,000 | |||||||||||||||||||
Convertible Subordinated Debt | Subsequent Event | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Debt instrument, face value | CAD 1,150,000,000 | CAD 1,000,000,000 | |||||||||||||||||||
Debt instrument, interest rate | 5.00% | ||||||||||||||||||||
Debt instrument, convertible, price per instrument paid at closing (CAD per debenture) | CAD 333,000,000 | ||||||||||||||||||||
Proceeds from issuance of debt | 150,000,000 | ||||||||||||||||||||
Proceeds from issuance of debt, first installment | CAD 49,950,000 |
Business acquisitions and dev62
Business acquisitions and development projects - Acquisition of Noncontrolling Interest (Details) CAD in Thousands, $ in Thousands | Mar. 31, 2014CAD | Mar. 31, 2014USD ($) | Dec. 31, 2015CAD | Dec. 31, 2014CAD |
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | CAD 159,672 | |||
Acquisition of non-controlling interest | CAD 0 | 127,121 | ||
Wind Portfolio SponsorCo, LLC | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest, decrease in deferred tax asset | CAD (32,551) | |||
Acquisition of non-controlling interest | 127,121 | $ 115,000 | ||
Non- controlling interests | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | 205,796 | |||
Non- controlling interests | Wind Portfolio SponsorCo, LLC | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | 205,796 | |||
Foreign currency cumulative translation | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | (21,029) | |||
Foreign currency cumulative translation | Wind Portfolio SponsorCo, LLC | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | (21,029) | |||
Unrealized gain on cash flow hedges | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | (2,543) | |||
Unrealized gain on cash flow hedges | Wind Portfolio SponsorCo, LLC | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | (2,543) | |||
Additional paid-in capital | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | CAD (22,552) | |||
Additional paid-in capital | Wind Portfolio SponsorCo, LLC | ||||
Business Acquisition [Line Items] | ||||
Acquisition of non-controlling interest | CAD (22,552) |
Accounts receivable - Additiona
Accounts receivable - Additional Information (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for doubtful accounts receivable | CAD 7,966 | CAD 7,229 |
Unbilled revenue | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable balances | CAD 49,002 | CAD 52,880 |
Property, plant and equipment64
Property, plant and equipment (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Line Items] | ||
Cost | CAD 4,535,068 | CAD 3,726,420 |
Accumulated depreciation | 661,384 | 447,998 |
Net book value | 3,873,684 | 3,278,422 |
Land | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 23,258 | 19,347 |
Accumulated depreciation | 0 | 0 |
Net book value | 23,258 | 19,347 |
Equipment and other | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 129,555 | 119,367 |
Accumulated depreciation | 37,443 | 29,526 |
Net book value | 92,112 | 89,841 |
Generation | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 2,138,748 | 1,827,247 |
Accumulated depreciation | 358,200 | 270,746 |
Net book value | 1,780,548 | 1,556,501 |
Generation | Construction in progress | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 64,779 | 82,840 |
Accumulated depreciation | 0 | 0 |
Net book value | 64,779 | 82,840 |
Distribution | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 2,075,059 | 1,555,289 |
Accumulated depreciation | 265,741 | 147,726 |
Net book value | 1,809,318 | 1,407,563 |
Distribution | Construction in progress | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 103,669 | 122,330 |
Accumulated depreciation | 0 | 0 |
Net book value | CAD 103,669 | CAD 122,330 |
Property, plant and equipment -
Property, plant and equipment - Additional Information (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant, and Equipment Disclosure [Line Items] | ||
Contribution received | CAD 9,623 | CAD 362 |
Water & wastewater | ||
Property, Plant, and Equipment Disclosure [Line Items] | ||
Expansion cost, distribution cost | 1,000 | |
Generation | ||
Property, Plant, and Equipment Disclosure [Line Items] | ||
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE | 158,514 | 155,629 |
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation | 38,507 | 34,013 |
Depreciation expense | CAD 2,117 | CAD 2,274 |
Intangible assets and goodwil66
Intangible assets and goodwill - Schedule of Intangible Assets (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Finite-Lived Intangible Assets [Line Items] | ||
Cost | CAD 128,808 | CAD 95,699 |
Accumulated amortization | 50,845 | 41,688 |
Net book value | 77,963 | 54,011 |
Power sales contracts | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 78,725 | 64,605 |
Accumulated amortization | 40,244 | 33,704 |
Net book value | 38,481 | 30,901 |
Customer relationships | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 37,083 | 31,094 |
Accumulated amortization | 10,371 | 7,984 |
Net book value | 26,712 | 23,110 |
Interconnection agreements | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 13,000 | 0 |
Accumulated amortization | 230 | 0 |
Net book value | CAD 12,770 | CAD 0 |
Intangible assets and goodwil67
Intangible assets and goodwill - Additional Information (Detail) CAD in Thousands | Dec. 31, 2015CAD |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
Estimated amortization expense for intangibles in year 1 | CAD 5,420 |
Estimated amortization expense for intangibles in year 2 | 3,620 |
Estimated amortization expense for intangibles in year 3 | 3,250 |
Estimated amortization expense for intangibles in year 4 | 3,200 |
Estimated amortization expense for intangibles in year 5 | CAD 3,160 |
Intangible assets and goodwil68
Intangible assets and goodwill - Schedule of Goodwill (Details) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill [Roll Forward] | ||
Goodwill beginning of the period | CAD 92,328 | CAD 84,647 |
Business acquisitions | 290 | |
Foreign exchange | 17,875 | 7,681 |
Goodwill end of the period | CAD 110,493 | CAD 92,328 |
Regulatory matters - Regulatory
Regulatory matters - Regulatory Assets and Liabilities (Additional Information) (Detail) CAD in Thousands, $ in Thousands | Feb. 18, 2016USD ($) | Feb. 10, 2016USD ($) | Jun. 26, 2015USD ($) | Mar. 12, 2015USD ($) | Feb. 11, 2015USD ($) | Dec. 04, 2014USD ($) | Dec. 03, 2014USD ($) | Apr. 18, 2014USD ($) | Mar. 17, 2014USD ($) | May. 31, 2014USD ($) | Dec. 31, 2015CAD |
Rate-base offset | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Regulatory liability, amortization period | 10 years | ||||||||||
Rate adjustment mechanism | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Collection period for services rendered | 24 months | ||||||||||
Environmental costs | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Regulatory assets recovery period | 7 years | ||||||||||
Pension and post-employment benefits | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Portion related to current acquisition | CAD | CAD 32,313 | ||||||||||
Regulatory asset approved not yet being recovered, average recovery term | 10 years | ||||||||||
Georgia Public Service | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved revenue increase | $ 3,680 | $ 3,235 | |||||||||
Georgia Public Service | Subsequent Event | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved revenue increase | $ 2,725 | ||||||||||
Massachusetts Department of Public Utilities | Subsequent Event | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved revenue increase | $ 7,800 | ||||||||||
New Hampshire Public Utilities Commission | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved revenue increase | $ 12,400 | ||||||||||
Approved rate increase | $ 10,875 | ||||||||||
Approved base rate increase | 9,760 | ||||||||||
Approved incremental capital expended | 1,115 | ||||||||||
Approved recovery of rate case expenses | $ 390 | ||||||||||
Arkansas Public Service Commission | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved revenue increase | $ 1,087 | ||||||||||
Illinois Commerce Commission | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved revenue increase | $ 4,625 | ||||||||||
Arizona Corporate Commission | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved rate increase | $ 1,767 | ||||||||||
Missouri Public Service Commission | |||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||
Approved rate increase | $ 4,868 |
Regulatory matters - Regulato70
Regulatory matters - Regulatory Assets and Liabilities (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 245,315 | CAD 247,272 |
Less current regulatory assets | (32,213) | (61,645) |
Non-current regulatory assets | 213,102 | 185,627 |
Total regulatory liabilities | 175,347 | 121,756 |
Less current regulatory liabilities | (44,167) | (20,590) |
Non-current regulatory liabilities | 131,180 | 101,166 |
Cost of removal | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 107,988 | 78,013 |
Rate-base offset | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 24,984 | 23,427 |
Commodity costs adjustment | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 32,423 | 10,389 |
Other | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 9,952 | 9,927 |
Environmental remediation | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 116,747 | 102,735 |
Pension and post-employment benefits | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 69,537 | 63,512 |
Commodity costs adjustment | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 7,643 | 41,502 |
Rate case costs | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 6,535 | 4,161 |
Rate adjustment mechanism | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 14,804 | 6,207 |
Other | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 30,049 | CAD 29,155 |
Long-term investments (Detail)
Long-term investments (Detail) CAD in Thousands, $ in Thousands | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Oct. 19, 2015 | Dec. 31, 2014CAD | Nov. 30, 2014 | Nov. 14, 2014 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Equity-method investees | CAD 52,473 | CAD 6,598 | ||||
Available-for-sale investment | 2,946 | 137 | ||||
Notes receivable | 119,383 | 39,510 | ||||
Total long-term investments | 174,802 | 46,245 | ||||
Less current portion | 0 | (2,966) | ||||
Total long-term investments | 174,802 | 43,279 | ||||
Notes Receivable | Development loans | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes receivable | 96,924 | 17,582 | ||||
Notes Receivable | Red Lily Senior loan, interest at 6.31% | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes receivable | CAD 11,588 | 11,588 | ||||
Note receivable interest rate | 6.31% | 6.31% | ||||
Notes Receivable | Red Lily Subordinated loan, interest at 12.5% | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes receivable | CAD 6,565 | 6,565 | ||||
Note receivable interest rate | 12.50% | 12.50% | ||||
Notes Receivable | Other | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes receivable | CAD 4,306 | 3,775 | ||||
50% interest in Odell Wind Project | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Equity-method investees | CAD 42,287 | 2,267 | ||||
Equity interest | 50.00% | 50.00% | 50.00% | |||
50% interest in Odell Wind Project | Notes Receivable | Development loans | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes receivable | $ | $ 62,751 | |||||
50% Interest in Deerfield Wind Project | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Equity-method investees | CAD 2,240 | 0 | ||||
Equity interest | 50.00% | 50.00% | 50.00% | |||
50% Interest in Deerfield Wind Project | Notes Receivable | Development loans | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Notes receivable | $ | $ 7,281 | |||||
Interest in Natural Gas Pipeline Development | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Equity-method investees | CAD 5,623 | 1,063 | ||||
Equity interest | 2.50% | |||||
Other | ||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||
Equity-method investees | CAD 2,323 | CAD 3,268 |
Long-term investments (Addition
Long-term investments (Additional Information) (Detail) | Feb. 23, 2016CAD | Oct. 19, 2015USD ($)memberMW | Oct. 06, 2015USD ($)member | Nov. 14, 2014USD ($)MW | Dec. 31, 2015CADmemberTranche | Nov. 30, 2014 | Dec. 31, 2016USD ($) | Dec. 31, 2015CADmemberTrancheMW | Dec. 31, 2015USD ($)MW | Dec. 31, 2014CAD | Dec. 31, 2011CAD | Dec. 31, 2015USD ($)memberTranche | Dec. 31, 2014USD ($) | Dec. 31, 2012CAD |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Notes receivable | CAD | CAD 119,383,000 | CAD 119,383,000 | CAD 39,510,000 | |||||||||||
Red Lily I Project, wind energy facility, capacity (in megawatt) | MW | 26.4 | 26.4 | ||||||||||||
Development loans | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Notes receivable | CAD | CAD 96,924,000 | CAD 96,924,000 | 17,582,000 | |||||||||||
Red Lily Senior loan, interest at 6.31% | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Note receivable interest rate | 6.31% | 6.31% | 6.31% | |||||||||||
Notes receivable | CAD | CAD 11,588,000 | CAD 11,588,000 | 11,588,000 | |||||||||||
Number of tranches | Tranche | 2 | 2 | 2 | |||||||||||
Prepayment received | CAD | CAD 1,412,000 | |||||||||||||
Red Lily Subordinated loan, interest at 12.5% | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Note receivable interest rate | 12.50% | 12.50% | 12.50% | |||||||||||
Notes receivable | CAD | CAD 6,565,000 | CAD 6,565,000 | 6,565,000 | |||||||||||
Red Lily Senior Loan Tranche 1 | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Third party payments to acquire note receivable | CAD | CAD 27,000,000 | |||||||||||||
Red Lily Senior Loan Tranche 2 | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Note receivable interest rate | 6.31% | 6.31% | 6.31% | |||||||||||
Third party payments to acquire note receivable | CAD | CAD 4,000,000 | |||||||||||||
Payments to acquire notes receivable | CAD | CAD 13,000,000 | |||||||||||||
50% interest in Odell and Deerfield Wind Projects | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Guarantee obligations | $ | $ 1,147,000 | |||||||||||||
50% interest in Odell and Deerfield Wind Projects | Development loans | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Stated interest rate after commercial operation | 5.00% | 5.00% | 5.00% | |||||||||||
Letter of credit fee percent | 2.00% | 2.00% | ||||||||||||
Note receivable termination period | 30 days | 30 days | ||||||||||||
Note receivable, term | 5 years | 5 years | ||||||||||||
50% interest in Odell and Deerfield Wind Projects | Development loans | Maximum | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Note receivable interest rate | 8.00% | 8.00% | 8.00% | |||||||||||
50% interest in Odell and Deerfield Wind Projects | Development loans | Minimum | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Note receivable interest rate | 7.00% | 7.00% | 7.00% | |||||||||||
50% Interest in Deerfield Wind Project | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Equity interest | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||
Project power capacity | MW | 150 | |||||||||||||
Number of members | member | 2 | 2 | 2 | 2 | ||||||||||
Contributions of capital | $ | $ 1,000,000 | |||||||||||||
Option to acquire percentage of ownership | 50.00% | 50.00% | ||||||||||||
Equity method investment, option to purchase, adjustment period | 90 days | 90 days | ||||||||||||
Interest capitalized on non-regulated property | CAD | CAD 94,000 | |||||||||||||
Maximum exposure to loss | CAD | CAD 321,472,000 | CAD 321,472,000 | ||||||||||||
50% Interest in Deerfield Wind Project | Deerfield SponsorCo | Letter of Credit | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Letter of credit issued | $ | $ 43,238,000 | |||||||||||||
50% Interest in Deerfield Wind Project | Development loans | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Notes receivable | $ | $ 7,281,000 | |||||||||||||
50% interest in Odell Wind Project | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Equity interest | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||
Project power capacity | MW | 200 | |||||||||||||
Number of members | member | 2 | 2 | 2 | 2 | ||||||||||
Contributions of capital | $ | $ 23,800,000 | $ 1,000,000 | ||||||||||||
Option to acquire percentage of ownership | 50.00% | 50.00% | ||||||||||||
Equity method investment, option to purchase, adjustment period | 30 days | 30 days | ||||||||||||
Interest capitalized on non-regulated property | CAD | CAD 4,415,000 | CAD 0 | ||||||||||||
Maximum exposure to loss | CAD | CAD 190,840,000 | CAD 190,840,000 | ||||||||||||
50% interest in Odell Wind Project | Development loans | Notes Receivable | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Notes receivable | $ | $ 62,751,000 | |||||||||||||
Interest in Odell Wind Project to Utility under the PPA | Odell SponsorCo | Letter of Credit | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Letter of credit issued | $ | 15,000,000 | |||||||||||||
Interest in Odell Wind Project Pursuant to the Generator Interconnection Agreement | Odell SponsorCo | Letter of Credit | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Letter of credit issued | $ | $ 1,119,000 | |||||||||||||
4.0% interest in natural gas transmission pipeline | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Equity interest | 4.00% | 4.00% | 4.00% | |||||||||||
4.0% interest in natural gas transmission pipeline | Maximum | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Option to subscribe equity interest in partnership, percentage | 10.00% | |||||||||||||
2.5% interest in natural gas pipeline development | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Equity interest | 2.50% | |||||||||||||
Total invested | $ | $ 4,063,000 | $ 375,000 | ||||||||||||
2.5% interest in natural gas pipeline development | Maximum | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Option to subscribe equity interest in partnership, percentage | 10.00% | 10.00% | 10.00% | |||||||||||
Investment commitment if option is exercised | $ | $ 520,000,000 | |||||||||||||
Subsequent Event | Red Lily | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Option to subscribe equity interest in partnership, exercisable period | 90 days | |||||||||||||
Subsequent Event | Maximum | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Subordinated loan to be advanced | CAD | CAD 15,588,000 | |||||||||||||
Subsequent Event | Maximum | Red Lily | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Option to subscribe equity interest in partnership, percentage | 75.00% | |||||||||||||
Plan | 50% Interest in Deerfield Wind Project | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Estimated construction costs | $ | $ 303,000,000 | |||||||||||||
Plan | 50% interest in Odell Wind Project | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Estimated construction costs | $ | $ 322,766,000 | |||||||||||||
Forecast | 50% Interest in Deerfield Wind Project | ||||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||||
Contributions of capital | $ | $ 18,596,000 | |||||||||||||
Equity method investment, contribution, percent of accrued interest | 7.00% |
Long-term debt (Detail)
Long-term debt (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Total | CAD 1,486,795 | CAD 1,271,719 |
Less: current portion | (8,945) | (9,130) |
Long-term debt, excluding current portion | 1,477,850 | 1,262,589 |
Generation | Revolving Credit Facility | ||
Debt Instrument [Line Items] | ||
Total | 27,300 | 23,400 |
Generation | Senior Unsecured Notes | Algonquin Power Co. Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Total | 481,991 | 481,438 |
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt | ||
Debt Instrument [Line Items] | ||
Total | 0 | 88,168 |
Generation | Senior Debt | Long Sault Hydro Facility Senior Debt | ||
Debt Instrument [Line Items] | ||
Total | 34,760 | 35,997 |
Generation | Senior Debt | Chuteford Hydro Facility Senior Debt | ||
Debt Instrument [Line Items] | ||
Total | 2,587 | 3,022 |
Distribution | ||
Debt Instrument [Line Items] | ||
Total | 946,782 | |
Distribution | Revolving Credit Facility | ||
Debt Instrument [Line Items] | ||
Total | 0 | 23,898 |
Distribution | Senior Unsecured Notes | Liberty Utilities Co. Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Total | 721,581 | 419,876 |
Distribution | Senior Unsecured Notes | Calpeco Electric System Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Total | 96,015 | 80,368 |
Distribution | Senior Unsecured Notes | Liberty Water Co, Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Total | 68,488 | 57,301 |
Distribution | Senior Unsecured Notes | Granite State, Senior Unsecured Long-term Notes | ||
Debt Instrument [Line Items] | ||
Total | 20,730 | 17,373 |
Distribution | Bonds | New England Gas System, First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Total | 32,130 | 27,288 |
Distribution | Bonds | LPSCo Water Bonds | ||
Debt Instrument [Line Items] | ||
Total | 0 | 12,441 |
Distribution | Loans | Bella Vista Water Loans | ||
Debt Instrument [Line Items] | ||
Total | CAD 1,213 | CAD 1,149 |
Long-term debt - Additional Inf
Long-term debt - Additional Information (Detail) | 12 Months Ended | ||||||||
Dec. 31, 2015CAD | Dec. 31, 2014CAD | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jul. 31, 2014CAD | Jul. 30, 2014CAD | Jan. 31, 2014CAD | Dec. 31, 2013CAD | Nov. 19, 2013USD ($) | |
Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of credit facility, maximum borrowing capacity | $ 65,000,000 | ||||||||
Generation | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of credit facility, maximum borrowing capacity | CAD | CAD 350,000,000 | CAD 200,000,000 | |||||||
Generation | Revolving Credit Facility | LIBOR | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of credit facility, maximum borrowing capacity | CAD | CAD 350,000,000 | CAD 350,000,000 | |||||||
Debt instrument, basis spread on variable rate | 1.45% | 1.45% | |||||||
Revolving credit facility, maturity date | Jul. 31, 2019 | Jul. 31, 2019 | |||||||
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 76,000,000 | ||||||||
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt | LIBOR | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, basis spread on variable rate | 2.80% | ||||||||
Generation | Senior Debt | Long Sault Hydro Facility Senior Debt | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | CAD | CAD 34,760,000 | CAD 34,760,000 | |||||||
Debt instrument, interest rate | 10.21% | 10.21% | 10.21% | 10.21% | |||||
Debt instrument, maturity date | Dec. 31, 2027 | Dec. 31, 2027 | |||||||
Generation | Senior Debt | Chuteford Hydro Facility Senior Debt | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | CAD | CAD 2,587,000 | CAD 2,587,000 | |||||||
Debt instrument, interest rate | 11.55% | 11.55% | 11.55% | 11.55% | |||||
Debt instrument, maturity date | Apr. 1, 2020 | Apr. 1, 2020 | |||||||
Generation | Senior Unsecured Notes | 4.65% Senior Unsecured Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | CAD | CAD 200,000,000 | CAD 200,000,000 | CAD 200,000,000 | ||||||
Debt instrument, interest rate | 4.65% | 4.65% | 4.65% | 4.65% | |||||
Debt instrument, maturity date | Feb. 15, 2022 | Feb. 15, 2022 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually in arrears. | The notes are interest only, payable semi-annually in arrears. | |||||||
Generation | Senior Unsecured Notes | 4.82% Senior Unsecured Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | CAD | CAD 150,000,000 | CAD 150,000,000 | CAD 150,000,000 | ||||||
Debt instrument, interest rate | 4.82% | 4.82% | 4.82% | 4.82% | |||||
Debt instrument, maturity date | Feb. 15, 2021 | Feb. 15, 2021 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually in arrears. | The notes are interest only, payable semi-annually in arrears. | |||||||
Generation | Senior Unsecured Notes | 5.5% Senior Unsecured Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | CAD | CAD 135,000,000 | CAD 135,000,000 | |||||||
Debt instrument, interest rate | 5.50% | 5.50% | 5.50% | 5.50% | |||||
Debt instrument, maturity date | Jul. 25, 2018 | Jul. 25, 2018 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually in arrears. | The notes are interest only, payable semi-annually in arrears. | |||||||
Distribution | Revolving Credit Facility | LIBOR | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of credit facility, maximum borrowing capacity | $ 200,000,000 | $ 200,000,000 | |||||||
Debt instrument, basis spread on variable rate | 1.25% | 1.25% | |||||||
Revolving credit facility, maturity date | Sep. 30, 2018 | Sep. 30, 2018 | |||||||
Distribution | Bonds | New England Gas System, First Mortgage Bonds, 9.44% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 6,500,000 | $ 6,500,000 | |||||||
Debt instrument, interest rate | 9.44% | 9.44% | 9.44% | 9.44% | |||||
Debt instrument, maturity date | Feb. 15, 2020 | Feb. 15, 2020 | |||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually in arrears. | The notes have interest only payments, payable semi-annually in arrears. | |||||||
Distribution | Bonds | New England Gas System, First Mortgage Bonds, 7.99% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 7,000,000 | $ 7,000,000 | |||||||
Debt instrument, interest rate | 7.99% | 7.99% | 7.99% | 7.99% | |||||
Debt instrument, maturity date | Sep. 15, 2026 | Sep. 15, 2026 | |||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually in arrears. | The notes have interest only payments, payable semi-annually in arrears. | |||||||
Distribution | Bonds | New England Gas System, First Mortgage Bonds, 7.24% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 6,000,000 | $ 6,000,000 | |||||||
Debt instrument, interest rate | 7.24% | 7.24% | 7.24% | 7.24% | |||||
Debt instrument, maturity date | Dec. 15, 2027 | Dec. 15, 2027 | |||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually in arrears. | The notes have interest only payments, payable semi-annually in arrears. | |||||||
Distribution | Bonds | Litchfield Park Service Company Bonds, 5.85% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, interest rate | 5.85% | 5.85% | 5.85% | 5.85% | |||||
Distribution | Bonds | Litchfield Park Service Company Bonds, 6.71% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, interest rate | 6.71% | 6.71% | 6.71% | 6.71% | |||||
Distribution | Loans | Bella Vista Water Loans, 6.26% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 877,000 | $ 877,000 | |||||||
Debt instrument, interest rate | 6.26% | 6.26% | 6.26% | 6.26% | |||||
Debt instrument, maturity date | Mar. 1, 2020 | Mar. 1, 2020 | |||||||
Debt instrument, repayment terms | The loans have principal and interest payments, payable monthly and quarterly in arrears. | The loans have principal and interest payments, payable monthly and quarterly in arrears. | |||||||
Distribution | Loans | Bella Vista Water Loans, 6.10% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 877,000 | $ 877,000 | |||||||
Debt instrument, interest rate | 6.10% | 6.10% | 6.10% | 6.10% | |||||
Debt instrument, maturity date | Dec. 1, 2017 | Dec. 1, 2017 | |||||||
Debt instrument, repayment terms | The loans have principal and interest payments, payable monthly and quarterly in arrears. | The loans have principal and interest payments, payable monthly and quarterly in arrears. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 3.51% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 50,000,000 | $ 50,000,000 | |||||||
Debt instrument, interest rate | 3.51% | 3.51% | 3.51% | 3.51% | |||||
Debt instrument, maturity date | Jul. 31, 2017 | Jul. 31, 2017 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 3.23% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 25,000,000 | $ 25,000,000 | |||||||
Debt instrument, interest rate | 3.23% | 3.23% | 3.23% | 3.23% | |||||
Debt instrument, maturity date | Jul. 31, 2020 | Jul. 31, 2020 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.49% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 115,000,000 | $ 115,000,000 | |||||||
Debt instrument, interest rate | 4.49% | 4.49% | 4.49% | 4.49% | |||||
Debt instrument, maturity date | Aug. 1, 2022 | Aug. 1, 2022 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.14% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 15,000,000 | $ 15,000,000 | |||||||
Debt instrument, interest rate | 4.14% | 4.14% | 4.14% | 4.14% | |||||
Debt instrument, maturity date | Mar. 13, 2023 | Mar. 13, 2023 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 3.86% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 75,000,000 | $ 75,000,000 | |||||||
Debt instrument, interest rate | 3.86% | 3.86% | 3.86% | 3.86% | |||||
Debt instrument, maturity date | Jul. 31, 2023 | Jul. 31, 2023 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.89% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 60,000,000 | $ 60,000,000 | |||||||
Debt instrument, interest rate | 4.89% | 4.89% | 4.89% | 4.89% | |||||
Debt instrument, maturity date | Jul. 30, 2027 | Jul. 30, 2027 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.26% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 25,000,000 | $ 25,000,000 | |||||||
Debt instrument, interest rate | 4.26% | 4.26% | 4.26% | 4.26% | |||||
Debt instrument, maturity date | Jul. 31, 2028 | Jul. 31, 2028 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.13%, Due April 30, 2045 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 90,000,000 | $ 90,000,000 | |||||||
Debt instrument, interest rate | 4.13% | 4.13% | 4.13% | 4.13% | |||||
Debt instrument, maturity date | Apr. 30, 2045 | Apr. 30, 2045 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Liberty Utilities Co Senior Unsecured Notes, 4.13%, Due July 15, 2045 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 70,000,000 | $ 70,000,000 | |||||||
Debt instrument, interest rate | 4.13% | 4.13% | 4.13% | 4.13% | |||||
Debt instrument, maturity date | Jul. 15, 2045 | Jul. 15, 2045 | |||||||
Debt instrument, repayment terms | The notes are interest only, payable semi-annually. | The notes are interest only, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Calpeco Electric System Senior Unsecured Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually in arrears. | The notes have interest only payments, payable semi-annually in arrears. | |||||||
Distribution | Senior Unsecured Notes | California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.19% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 45,000,000 | $ 45,000,000 | |||||||
Debt instrument, interest rate | 5.19% | 5.19% | 5.19% | 5.19% | |||||
Debt instrument, maturity date | Dec. 29, 2020 | Dec. 29, 2020 | |||||||
Distribution | Senior Unsecured Notes | California Pacific Electric Company, LLC, Senior Unsecured Notes, 5.59% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 25,000,000 | $ 25,000,000 | |||||||
Debt instrument, interest rate | 5.59% | 5.59% | 5.59% | 5.59% | |||||
Debt instrument, maturity date | Dec. 29, 2025 | Dec. 29, 2025 | |||||||
Distribution | Senior Unsecured Notes | Liberty Water Co, Senior Unsecured Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 50,000,000 | $ 50,000,000 | |||||||
Debt instrument, interest rate | 5.60% | 5.60% | 5.60% | 5.60% | |||||
Annual principal payment | $ 5,000,000 | $ 5,000,000 | |||||||
Balloon payment paid at maturity | 25,000,000 | 25,000,000 | |||||||
Debt instrument, maturity date | Dec. 22, 2020 | Dec. 22, 2020 | |||||||
Debt instrument, repayment terms | The note bears interest payments semi-annually in arrears. | The note bears interest payments semi-annually in arrears. | |||||||
Distribution | Senior Unsecured Notes | Granite State Senior Unsecured Longterm Notes, 7.37% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 5,000,000 | $ 5,000,000 | |||||||
Debt instrument, interest rate | 7.37% | 7.37% | 7.37% | 7.37% | |||||
Debt instrument, maturity date | Nov. 1, 2023 | Nov. 1, 2023 | |||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually. | The notes have interest only payments, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Granite State Senior Unsecured Longterm Notes, 7.94% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 5,000,000 | $ 5,000,000 | |||||||
Debt instrument, interest rate | 7.94% | 7.94% | 7.94% | 7.94% | |||||
Debt instrument, maturity date | Jul. 1, 2025 | Jul. 1, 2025 | |||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually. | The notes have interest only payments, payable semi-annually. | |||||||
Distribution | Senior Unsecured Notes | Granite State Senior Unsecured Longterm Notes, 7.30% | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, face value | $ 5,000,000 | $ 5,000,000 | |||||||
Debt instrument, interest rate | 7.30% | 7.30% | 7.30% | 7.30% | |||||
Debt instrument, maturity date | Jun. 15, 2028 | Jun. 15, 2028 | |||||||
Debt instrument, repayment terms | The notes have interest only payments, payable semi-annually. | The notes have interest only payments, payable semi-annually. |
Long-term debt Long-term debt -
Long-term debt Long-term debt - Narrative (Detail) | Mar. 01, 2016CAD | Feb. 09, 2016CAD | Oct. 30, 2015CAD | Oct. 01, 2015USD ($) | Jul. 15, 2015USD ($) | May. 12, 2015USD ($) | Apr. 30, 2015USD ($)Tranche | Dec. 31, 2014USD ($) | Mar. 10, 2016 | Dec. 31, 2015CAD | Dec. 31, 2014CAD | Feb. 09, 2016USD ($) | Jan. 04, 2016USD ($)bank | Dec. 31, 2015USD ($) | Oct. 30, 2015USD ($) | Dec. 31, 2014USD ($) | Jul. 31, 2014CAD | Jul. 30, 2014CAD | Jan. 17, 2014CAD | Nov. 19, 2013USD ($) |
Debt Instrument [Line Items] | ||||||||||||||||||||
Deferred finance costs | CAD | CAD 3,211,000 | CAD 2,428,000 | ||||||||||||||||||
Repayment of debt | CAD | 196,149,000 | 286,552,000 | ||||||||||||||||||
Interest on long term debt | CAD | 25,161,000 | 18,770,000 | ||||||||||||||||||
Interest expense during the year on long-term liabilities | CAD | CAD 72,213,000 | 64,218,000 | ||||||||||||||||||
Revolving Credit Facility | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 65,000,000 | |||||||||||||||||||
long-term line of credit outstanding | $ 0 | $ 0 | ||||||||||||||||||
Generation | Senior Unsecured Notes | 4.65% Senior Unsecured Debentures Due 2022 | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Deferred finance costs | CAD | CAD 1,568,000 | |||||||||||||||||||
Debt instrument, face value | CAD | CAD 200,000,000 | |||||||||||||||||||
Debt instrument, interest rate | 4.65% | |||||||||||||||||||
Debt instrument sold, price per principal amount | 0.99864 | |||||||||||||||||||
Generation | Revolving Credit Facility | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD | CAD 350,000,000 | CAD 200,000,000 | ||||||||||||||||||
Period of development | 3 years | |||||||||||||||||||
Generation | Senior Debt | Sanger Terminal Facility Bonds | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Repayment of debt | $ 19,200,000 | |||||||||||||||||||
Generation | Senior Debt | Shady Oaks Wind Facility Senior Debt | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Repayment of debt | $ 76,000,000 | |||||||||||||||||||
Debt instrument, face value | $ 76,000,000 | |||||||||||||||||||
Distribution | Senior Unsecured Thirty Year Note via Private Placement | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Proceeds from issuance of senior long-term debt | $ 70,000,000 | $ 90,000,000 | ||||||||||||||||||
Distribution | Bonds | LPSCo Water Bonds | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Repayment of debt | $ 9,800,000 | |||||||||||||||||||
Distribution | Senior Debt | Senior Unsecured Thirty Year Note via Private Placement | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Debt instrument, term | 30 years | |||||||||||||||||||
Debt instrument, face value | $ 160,000,000 | |||||||||||||||||||
Debt instrument, interest rate | 4.13% | |||||||||||||||||||
Debt instrument, number of tranches | Tranche | 2 | |||||||||||||||||||
Long-term Debt | New Accounting Pronouncement, Early Adoption, Effect | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Deferred finance costs | CAD | 8,304,000 | |||||||||||||||||||
Other Assets | New Accounting Pronouncement, Early Adoption, Effect | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Deferred finance costs | CAD | CAD (8,304,000) | |||||||||||||||||||
Letter of Credit | Generation | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Debt instrument, term | 1 year | |||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD 50,000,000 | $ 30,000,000 | ||||||||||||||||||
Subsequent Event | Revolving Credit Facility | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, term extension | 1 year | |||||||||||||||||||
Subsequent Event | Bridge Financing Commitments | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD 2,200,000,000 | $ 1,600,000,000 | ||||||||||||||||||
Subsequent Event | Bridge Financing Commitments | Debt Bridge Facility | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,065,000,000 | |||||||||||||||||||
Line of credit facility, advance repayable, maximum time period | 1 year | |||||||||||||||||||
Subsequent Event | Bridge Financing Commitments | Equity Bridge Facility | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 535,000,000 | |||||||||||||||||||
Line of credit facility, increase (decrease) of borrowing capacity | CAD | CAD (359,950,000) | |||||||||||||||||||
Line of credit facility, advance repayable, maximum time period | 1 year | |||||||||||||||||||
Subsequent Event | Line of Credit | ||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 235,000,000 | |||||||||||||||||||
Line of credit facility, number of banks | bank | 2 |
Long-term debt Long-term debt76
Long-term debt Long-term debt - Principal Payments (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Long-term Debt, Fiscal Year Maturity [Abstract] | ||
2,016 | CAD 8,945 | |
2,017 | 78,403 | |
2,018 | 144,407 | |
2,019 | 37,301 | |
2,020 | 150,281 | |
Thereafter | 1,076,786 | |
Long-term debt | 1,486,795 | CAD 1,271,719 |
Total, including adjustment | 1,496,123 | |
Generation | ||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||
2,016 | 1,816 | |
2,017 | 2,045 | |
2,018 | 137,272 | |
2,019 | 30,152 | |
2,020 | 2,641 | |
Thereafter | 375,415 | |
Total, including adjustment | 549,341 | |
Distribution | ||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||
2,016 | 7,129 | |
2,017 | 76,358 | |
2,018 | 7,135 | |
2,019 | 7,149 | |
2,020 | 147,640 | |
Thereafter | 701,371 | |
Long-term debt | CAD 946,782 |
Pension and other post-retire77
Pension and other post-retirement benefits - Additional Information (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Employee Benefits Disclosure [Line Items] | ||
Defined contribution pension plan cost | CAD 4,132 | CAD 3,287 |
Accumulated benefit obligation for pension plan | 251,932 | CAD 219,007 |
Defined benefit plan, amounts recognized in other comprehensive income (loss), net prior service cost (credit) | 3,941 | |
Pension Plans | ||
Employee Benefits Disclosure [Line Items] | ||
Net actuarial loss for defined benefit pension plan that will be amortized from accumulated other comprehensive income over next fiscal year | 632 | |
Expected employer contributions for next year | 9,232 | |
Other Postretirement Benefit Plans, Defined Benefit | ||
Employee Benefits Disclosure [Line Items] | ||
Net actuarial loss for defined benefit pension plan that will be amortized from accumulated other comprehensive income over next fiscal year | 88 | |
Expected employer contributions for next year | CAD 4,237 |
Pension and other post-retire78
Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans | ||
Change in projected benefit obligation | ||
Projected benefit obligation, beginning of year | CAD 241,963 | CAD 178,113 |
Projected benefit obligation assumed from business combination | 0 | 1,022 |
Modifications to pension plan | (4,995) | (560) |
Service cost | 6,663 | 4,828 |
Interest cost | 9,642 | 8,549 |
Actuarial loss (gain) | (16,098) | 39,704 |
Contributions from retirees | 0 | 0 |
Benefits paid | (13,024) | (8,125) |
Loss on foreign exchange | 45,231 | 18,432 |
Projected benefit obligation, at end of year | 269,382 | 241,963 |
Change in plan assets | ||
Fair value of plan assets, beginning of year | 156,990 | 139,280 |
Actual return (loss) on plan assets | (5,657) | 6,568 |
Employer contributions | 7,975 | 5,676 |
Benefits paid | (12,589) | (7,414) |
Gain on foreign exchange | 29,453 | 12,880 |
Fair value of plan assets, end of year | 176,172 | 156,990 |
Unfunded status | (93,210) | (84,973) |
Current liabilities | (470) | 0 |
Non-current liabilities | (92,740) | (84,973) |
Net amount recognized | (93,210) | (84,973) |
Other Postretirement Benefit Plans, Defined Benefit | ||
Change in projected benefit obligation | ||
Projected benefit obligation, beginning of year | 68,257 | 45,399 |
Projected benefit obligation assumed from business combination | 0 | 0 |
Modifications to pension plan | 0 | 0 |
Service cost | 3,093 | 2,022 |
Interest cost | 2,914 | 2,186 |
Actuarial loss (gain) | (8,466) | 14,893 |
Contributions from retirees | 412 | 331 |
Benefits paid | (2,447) | (1,586) |
Loss on foreign exchange | 12,802 | 5,012 |
Projected benefit obligation, at end of year | 76,565 | 68,257 |
Change in plan assets | ||
Fair value of plan assets, beginning of year | 14,295 | 13,395 |
Actual return (loss) on plan assets | 20 | 1,176 |
Employer contributions | 3,028 | (222) |
Benefits paid | (2,036) | (1,255) |
Gain on foreign exchange | 2,842 | 1,201 |
Fair value of plan assets, end of year | 18,149 | 14,295 |
Unfunded status | (58,416) | (53,962) |
Current liabilities | (1,062) | (333) |
Non-current liabilities | (57,354) | (53,629) |
Net amount recognized | CAD (58,416) | CAD (53,962) |
Pension and other post-retire79
Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans | ||
Accumulated Other Comprehensive Income, Pension and Other Post-retirement Benefits | ||
Beginning balance | CAD 28,751 | CAD (14,385) |
Current year net actuarial gain (loss) | 1,505 | 43,350 |
Current year prior service credits | (4,864) | (563) |
Amortization of net actuarial loss (gains) | 1,358 | 349 |
Amortization of prior service credits | 457 | |
Ending balance | 24,491 | 28,751 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Accumulated Other Comprehensive Income, Pension and Other Post-retirement Benefits | ||
Beginning balance | 5,896 | (9,083) |
Current year net actuarial gain (loss) | (7,554) | 14,338 |
Current year prior service credits | 0 | 0 |
Amortization of net actuarial loss (gains) | 680 | 641 |
Amortization of prior service credits | 0 | |
Ending balance | CAD (2,338) | CAD 5,896 |
Pension and other post-retire80
Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 3.71% | 4.55% |
Expected return on assets | 6.44% | 7.00% |
Rate of compensation increase | 3.01% | 2.97% |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 3.82% | 4.60% |
Expected return on assets | 5.50% | 5.53% |
Health care cost trend rate | ||
Before Age 65 | 7.00% | 7.63% |
Age 65 and after | 7.00% | 7.63% |
Assumed Ultimate Medical Inflation Rate | 5.00% | 5.00% |
Year in which Ultimate Rate is reached | 2,019 | 2,019 |
Pension and other post-retire81
Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.16% | 3.71% |
Rate of compensation increase | 3.00% | 3.01% |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.23% | 3.80% |
Health care cost trend rate | ||
Before Age 65 | 6.50% | 7.00% |
Age 65 and after | 6.50% | 7.00% |
Assumed Ultimate Medical Inflation Rate | 4.75% | 5.00% |
Year in which Ultimate Rate is reached | 2,023 | 2,019 |
Pension and other post-retire82
Pension and other post-retirement benefits - Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR) (Detail) CAD in Thousands | 12 Months Ended |
Dec. 31, 2015CAD | |
Compensation and Retirement Disclosure [Abstract] | |
Effect of a 1 percentage point increase in the HCCTR on year-end benefit obligation | CAD 10,763 |
Effect of a 1 percentage point increase in the HCCTR on total service and interest cost | 1,111 |
Effect of a 1 percentage point decrease in the HCCTR on, year-end benefit obligation | (8,687) |
Effect of a 1 percentage point decrease in the HCCTR on, total service and interest cost | CAD (871) |
Pension and other post-retire83
Pension and other post-retirement benefits - Components of Net Benefit Costs for Pension Plans and OPEB Recorded as Part of Administrative Expenses (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | CAD 6,663 | CAD 4,828 |
Interest cost | 9,642 | 8,549 |
Expected return on plan assets | (11,989) | (10,018) |
Amortization of net actuarial loss (gain) | 1,398 | (346) |
Amortization of prior service credits | (471) | 0 |
Net benefit cost | 5,243 | 3,013 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 3,093 | 2,022 |
Interest cost | 2,914 | 2,186 |
Expected return on plan assets | (713) | (628) |
Amortization of net actuarial loss (gain) | 510 | (641) |
Amortization of prior service credits | 0 | 0 |
Net benefit cost | CAD 5,804 | CAD 2,939 |
Pension and other post-retire84
Pension and other post-retirement benefits - Target Plan Asset Allocation (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 73.85% |
Target allocation percentage range, minimum | 49.00% |
Target allocation percentage range, maximum | 78.00% |
Debt securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 25.71% |
Target allocation percentage range, minimum | 22.00% |
Target allocation percentage range, maximum | 51.00% |
Other | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 0.45% |
Target allocation percentage range, minimum | 0.00% |
Target allocation percentage range, maximum | 1.00% |
Pension and other post-retire85
Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) CAD in Thousands | Dec. 31, 2015CAD |
Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Allocation percentage | 72.00% |
Equity securities | Level 1 | |
Defined Benefit Plan Disclosure [Line Items] | |
Fair value of plan assets | CAD 138,993 |
Debt securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Allocation percentage | 28.00% |
Debt securities | Level 1 | |
Defined Benefit Plan Disclosure [Line Items] | |
Fair value of plan assets | CAD 54,542 |
Other | |
Defined Benefit Plan Disclosure [Line Items] | |
Allocation percentage | 0.00% |
Other | Level 1 | |
Defined Benefit Plan Disclosure [Line Items] | |
Fair value of plan assets | CAD 787 |
Pension and other post-retire86
Pension and other post-retirement benefits - Expected Benefit Payments (Detail) CAD in Thousands | Dec. 31, 2015CAD |
Pension Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | CAD 15,037 |
2,017 | 13,829 |
2,018 | 14,474 |
2,019 | 15,120 |
2,020 | 15,692 |
2021-2025 | 88,692 |
Post Retirement Benefit Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | 3,113 |
2,017 | 3,375 |
2,018 | 3,584 |
2,019 | 3,804 |
2,020 | 4,396 |
2021-2025 | CAD 25,720 |
Mandatorily redeemable Series87
Mandatorily redeemable Series C preferred shares (Details) - CAD CAD / shares in Units, CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Jan. 01, 2013 |
Disclosure Estimated Dividend And Redemption Payments [Abstract] | |||
2,016 | CAD 8,945 | ||
2,017 | 78,403 | ||
2,018 | 144,407 | ||
2,019 | 37,301 | ||
2,020 | 150,281 | ||
Thereafter to 2031 | 1,076,786 | ||
Preferred Shares Series C, noncurrent | CAD 17,548 | CAD 17,608 | |
Series C Preferred Stock | |||
Class of Stock [Line Items] | |||
Redeemable preferred stock issued, shares | 100 | 100,000 | |
Preferred stock redemption price per share (in dollars per share) | CAD 53,400 | ||
Disclosure Estimated Dividend And Redemption Payments [Abstract] | |||
Less amounts representing interest | CAD (10,910) | ||
Total Preferred shares series C | 18,527 | ||
Less current portion | (979) | ||
Preferred Shares Series C, noncurrent | CAD 17,548 | ||
Executives of company | Series C Preferred Stock | |||
Class of Stock [Line Items] | |||
Redeemable preferred stock issued, shares | 36 | ||
Dividends Payable | Series C Preferred Stock | |||
Disclosure Estimated Dividend And Redemption Payments [Abstract] | |||
2,016 | CAD 979 | ||
2,017 | 908 | ||
2,018 | 1,068 | ||
2,019 | 1,282 | ||
2,020 | 1,344 | ||
Thereafter to 2031 | 18,516 | ||
Redemption amount | 5,340 | ||
Estimated dividend and redemption payments | CAD 29,437 |
Other assets (Detail)
Other assets (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Restricted cash | CAD 18,999 | CAD 18,702 |
Deferred financing costs | 3,211 | 2,428 |
Other | 4,770 | 4,475 |
Total other assets | 26,980 | 25,605 |
Less current portion | (464) | 0 |
Other assets | CAD 26,516 | CAD 25,605 |
Other long-term liabilities a89
Other long-term liabilities and deferred credits (Detail) - CAD CAD in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Long-term Liabilities | |||
Advances in aid of construction (a) | CAD 92,285 | CAD 81,104 | |
Asset retirement obligations (c) | 17,799 | 13,884 | |
Customer deposits (d) | 15,074 | 11,713 | |
Deferred income (e) | 13,682 | 13,132 | |
Deferred credits (f) | 24,110 | 19,130 | |
Other | 25,277 | 17,503 | |
Other Liabilities | 259,756 | 226,538 | |
Less current portion | 36,621 | 49,303 | |
Other long-term liabilities | 223,135 | 177,235 | |
Transfers from advances in aid of construction to contributions in aid of construction | 4,637 | 4,608 | |
Estimated environmental remediation costs | 78,495 | 72,594 | |
Estimated environmental remediation costs, net | 71,529 | 70,072 | CAD 69,555 |
Accrual for environmental loss contingencies to be incurred over next three years | CAD 46,929 | ||
Accrual for environmental loss contingencies, payment period | 29 years | ||
Amount of regulatory assets | CAD 245,315 | 247,272 | |
Additional asset retirement obligation recorded | 506 | 2,570 | |
Accretion expense | 854 | 527 | |
Deferred tax credit | CAD 3,350 | 19,130 | |
Minimum | |||
Other Long-term Liabilities | |||
Other liability repayment period | 10 years | ||
Accrual environmental cost | 2.50% | ||
Maximum | |||
Other Long-term Liabilities | |||
Other liability repayment period | 20 years | ||
Accrual environmental cost | 4.20% | ||
Environmental costs | |||
Other Long-term Liabilities | |||
Regulatory asset, expenditure recovery provided by regulator, time period | 7 years | ||
Amount of regulatory assets | CAD 116,747 | CAD 102,735 |
Other long-term liabilities a90
Other long-term liabilities and deferred credits - Changes in Environmental Remediation Obligation (Details) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Accrual for Environmental Loss Contingencies [Roll Forward] | ||
Opening Balance | CAD 70,072 | CAD 69,555 |
Remediation activities | (10,621) | (12,739) |
Accretion | 2,147 | 2,273 |
Changes in cash flow estimates | 3,171 | 268 |
Revision in assumptions | (5,843) | 1,954 |
Purchase price adjustment | 0 | 2,726 |
Foreign exchange rate adjustment | 12,603 | 6,035 |
Closing Balance | CAD 71,529 | CAD 70,072 |
Shareholders' capital - Common
Shareholders' capital - Common Shares (Detail) - shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Common Shares Rollforward | ||
Beginning balance (in shares) | 238,149,468 | 206,348,985 |
Public offering (in shares) | 14,355,000 | 29,444,000 |
Issuance of shares under the dividend reinvestment and employee share purchase plans (in shares) | 3,364,951 | 2,356,483 |
Ending balance (in shares) | 255,869,419 | 238,149,468 |
Shareholders' capital - Additio
Shareholders' capital - Additional Information (Detail) CAD / shares in Units, CAD in Thousands | Dec. 29, 2014CADCAD / sharesshares | Dec. 31, 2015CADCAD / sharesshares | Dec. 31, 2014CADCAD / sharesshares | Sep. 30, 2014CADCAD / sharesshares | Mar. 10, 2016shares | Dec. 31, 2015CADRightCAD / sharesshares | Dec. 31, 2014CADCAD / sharesshares | Jan. 01, 2013shares |
Stockholders Equity Note [Line Items] | ||||||||
Number of voting rights per share | Right | 1 | |||||||
Discount rate on share purchases | 50.00% | |||||||
Common shares issued | shares | 14,355,000 | 29,444,000 | ||||||
Proceeds from subscription receipts | CAD 0 | CAD 110,503 | ||||||
Discount rate on share purchases under dividend reinvestment plan | 5.00% | |||||||
Carrying amount | CAD 213,805 | CAD 213,805 | CAD 213,805 | 213,805 | ||||
Total share-based compensation expense | CAD 5,330 | 3,248 | ||||||
Death Benefits | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Stock options exercised period | 1 year | |||||||
Resignation or Termination | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Stock options exercised period | 30 days | |||||||
Maximum | Retirement | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Stock options exercised period | 90 days | |||||||
Minimum | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Percentage of outstanding stock to be purchased to acquire discount (or more) | 20.00% | |||||||
Subsequent Event | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Additional shares issued under dividend reinvestment plan | shares | 292,337 | |||||||
Employee Stock Option | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Total share-based compensation expense | CAD 2,742 | 1,931 | ||||||
Unrecognized compensation costs, non-vested options | CAD 3,125 | CAD 3,125 | ||||||
Unrecognized compensation costs, non-vested options, period of recognition | 1 year 8 months 27 days | |||||||
Stock Option Plans | Maximum | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Percentage of shares reserves under plan (must not exceed) | 10.00% | |||||||
Performance Share Units | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Performance share units granting period | 3 years | |||||||
Percentage of shares issued on number of PSU grants, minimum | 0.00% | |||||||
Percentage of shares issued on number of PSU grants, maximum | 197.50% | |||||||
Employee share purchase | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Total share-based compensation expense | CAD 158 | CAD 116 | ||||||
Vesting period of matching contribution shares | 1 year | |||||||
Maximum aggregate number of shares reserved for issuance from treasury | shares | 2,000,000 | 2,000,000 | ||||||
Common stock, shares issued | shares | 111,355 | 93,598 | 111,355 | 93,598 | ||||
Deferred Share Units | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Shares issued during period | shares | 157,471 | 110,241 | ||||||
Performance share units | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Total share-based compensation expense | CAD 2,026 | CAD 928 | ||||||
Unrecognized compensation costs, non-vested awards | CAD 1,866 | CAD 1,866 | ||||||
Unrecognized compensation costs, non-vested options, period of recognition | 1 year 7 months 17 days | |||||||
Percent of performance goals achieved | 100.00% | |||||||
Series A Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 25 | CAD 25 | CAD 25 | CAD 25 | ||||
Preferred stock issued, shares | shares | 4,800,000 | 4,800,000 | 4,800,000 | 4,800,000 | ||||
Carrying amount | CAD 116,546 | CAD 116,546 | CAD 116,546 | CAD 116,546 | ||||
Fixed cumulative annual dividend per share | CAD / shares | CAD 1.125 | CAD 1.125 | ||||||
Subsequent yield period | 5 years | |||||||
Preferred stock redemption price per share (in dollars per share) | CAD / shares | 25 | CAD 25 | ||||||
Series C Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Preferred stock redemption price per share (in dollars per share) | CAD / shares | CAD 53,400 | CAD 53,400 | ||||||
Redeemable preferred stock issued, shares | shares | 100 | 100 | 100,000 | |||||
Series D Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 25 | CAD 25 | CAD 25 | CAD 25 | ||||
Preferred stock issued, shares | shares | 4,000,000 | 4,000,000 | 4,000,000 | 4,000,000 | ||||
Carrying amount | CAD 97,259 | CAD 97,259 | CAD 97,259 | CAD 97,259 | ||||
Fixed cumulative annual dividend per share | CAD / shares | CAD 1.25 | CAD 1.25 | ||||||
Common shares | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Common shares issued | shares | 14,355,000 | 10,055,000 | 19,389,000 | |||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 10.45 | CAD 9.95 | CAD 8.90 | CAD 10.45 | CAD 9.95 | |||
Cash proceeds from issuance of shares | CAD 150,010 | CAD 100,047 | CAD 172,562 | |||||
Stock issuance cost | 4,243 | 7,648 | CAD 6,735 | |||||
Stock issuance costs, net of tax | CAD 5,023 | CAD 3,021 | CAD 5,719 | |||||
Government of Canada Bond Yield | Series A Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Dividend variable interest rate | 2.94% | |||||||
Government of Canada Bond Yield | Series D Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Dividend variable interest rate | 3.28% | |||||||
Government of Canada Treasury Bill Yield | Series B Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Dividend variable interest rate | 2.94% | |||||||
Government of Canada Treasury Bill Yield | Series E Preferred Stock | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Dividend variable interest rate | 3.28% | |||||||
Emera | Subscription receipts | Park Water Company | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Common shares issued | shares | 3,316,583 | |||||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 9.95 | |||||||
Proceeds from subscription receipts | CAD 33,000 | |||||||
Emera | Interest in Odell Wind Project | Subscription receipts | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Common shares issued | shares | 8,708,170 | |||||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 8.90 | |||||||
Proceeds from subscription receipts | CAD 77,503 | |||||||
Range One | Employee share purchase | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Employer matching contribution, percent | 20.00% | |||||||
Range Two | Employee share purchase | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Employer matching contribution, percent | 10.00% | |||||||
Range Three | Employee share purchase | ||||||||
Stockholders Equity Note [Line Items] | ||||||||
Employer matching contribution, percent | 15.00% |
Shareholder's capital - Share-B
Shareholder's capital - Share-Based Compensation Expense (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | CAD 5,330 | CAD 3,248 |
Share options | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | 2,742 | 1,931 |
Directors deferred share units | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | 404 | 273 |
Employee share purchase | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | 158 | 116 |
Performance share units | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | CAD 2,026 | CAD 928 |
Shareholders' capital - Fair Va
Shareholders' capital - Fair Value of Share Options Granted (Detail) - CAD / shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Equity [Abstract] | ||
Risk-free interest rate | 1.30% | 2.00% |
Expected volatility | 38.00% | 38.00% |
Expected dividend yield | 4.00% | 3.80% |
Expected life | 8 years | 8 years |
Weighted average grant date fair value per option (CAD per share) | CAD 2.45 | CAD 2 |
Shareholders' capital - Stock O
Shareholders' capital - Stock Option Activity (Detail) - CAD CAD / shares in Units, CAD in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Number of awards | |||
Beginning balance, Shares | 5,537,127 | 4,567,129 | |
Granted, Shares | 1,627,525 | 969,998 | |
Ending balance, Shares | 7,164,652 | 5,537,127 | 4,567,129 |
Exercisable, Shares | 4,618,323 | ||
Weighted average exercise price | |||
Beginning balance (CAD per share) | CAD 6.09 | CAD 5.70 | |
Granted (CAD per share) | 9.75 | 7.95 | |
Ending balance (CAD per share) | 6.92 | CAD 6.09 | CAD 5.70 |
Exercisable (CAD per share) | CAD 5.74 | ||
Additional Disclosures | |||
Outstanding shares, weighted average remaining contractual term | 4 years 8 months 27 days | 4 years 11 months 16 days | 5 years 5 months 12 days |
Granted, Weighted average remaining contractual term | 8 years | 8 years | |
Exercisable , Weighted average remaining contractual term | 3 years 6 months 18 days | ||
Beginning balance, aggregate intrinsic value | CAD 19,648 | CAD 7,814 | |
Granted, aggregate intrinsic value | 0 | 0 | |
Ending balance, aggregate intrinsic value | 28,561 | CAD 19,648 | CAD 7,814 |
Exercisable , aggregate intrinsic value | CAD 23,898 |
Shareholder's capital - Perform
Shareholder's capital - Performance Stock Units (Detail) - Performance share units - CAD CAD / shares in Units, CAD in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Number of awards | |||
Beginning balance, Shares | 440,086 | 66,195 | |
Granted, Shares | 212,250 | 407,962 | |
Exercised, Shares | (41,131) | (22,665) | |
Forfeited, Shares | (47,089) | (11,406) | |
Ending balance, Shares | 564,116 | 440,086 | 66,195 |
Exercisable, Shares | 157,972 | ||
Weighted average grant-date fair value | |||
Beginning balance (CAD per share) | CAD 6.57 | CAD 6.57 | |
Granted (CAD per share) | 9.72 | 8.22 | |
Exercised (CAD per share) | 6.86 | 6.13 | |
Forfeited (CAD per share) | 8.30 | 8.22 | |
Ending balance (CAD per share) | 7.59 | CAD 6.57 | CAD 6.57 |
Exercisable (CAD per share) | CAD 8.22 | ||
Additional Disclosures | |||
Outstanding, Weighted average remaining contractual term | 1 year 7 months 17 days | 1 year 9 months 22 days | 7 months 13 days |
Granted, Weighted average remaining contractual term | 2 years 7 months 13 days | 3 years | |
Outstanding, aggregate intrinsic value | CAD 6,155 | CAD 4,242 | CAD 486 |
Granted, aggregate intrinsic value | 0 | 3,333 | |
Exercised, aggregate intrinsic value | 381 | (185) | |
Forfeited, aggregate intrinsic value | 0 | CAD (93) | |
Exercisable, aggregate intrinsic value | CAD 1,723 |
Accumulated other comprehensi97
Accumulated other comprehensive income (loss) (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning balance | CAD 34,213 | |
Other comprehensive income, net of tax | 312,698 | CAD 71,314 |
Acquisition of non-controlling interest | (159,672) | |
Ending balance | 286,737 | 34,213 |
Foreign currency cumulative translation | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning balance | 32,496 | (57,471) |
OCI (loss) before reclassifications | 228,861 | 68,938 |
Amounts reclassified | 0 | 0 |
Other comprehensive income, net of tax | 228,861 | 68,938 |
Acquisition of non-controlling interest | 21,029 | |
Ending balance | 261,357 | 32,496 |
Unrealized gain on cash flow hedges | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning balance | 23,164 | 11,840 |
OCI (loss) before reclassifications | 21,896 | 3,358 |
Amounts reclassified | (5,731) | 5,423 |
Other comprehensive income, net of tax | 16,165 | 8,781 |
Acquisition of non-controlling interest | 2,543 | |
Ending balance | 39,329 | 23,164 |
Net change on available-for-sale investments | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning balance | 1 | 0 |
OCI (loss) before reclassifications | (73) | 519 |
Amounts reclassified | 0 | (518) |
Other comprehensive income, net of tax | (73) | 1 |
Acquisition of non-controlling interest | 0 | |
Ending balance | (72) | 1 |
Pension and post-employment actuarial changes | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning balance | (21,448) | 14,221 |
OCI (loss) before reclassifications | 6,487 | (35,396) |
Amounts reclassified | 1,084 | (273) |
Other comprehensive income, net of tax | 7,571 | (35,669) |
Acquisition of non-controlling interest | 0 | |
Ending balance | (13,877) | (21,448) |
Accumulated OCI | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning balance | 34,213 | (31,410) |
OCI (loss) before reclassifications | 257,171 | 37,419 |
Amounts reclassified | (4,647) | 4,632 |
Other comprehensive income, net of tax | 252,524 | 42,051 |
Acquisition of non-controlling interest | 23,572 | |
Ending balance | CAD 286,737 | CAD 34,213 |
Dividends (Detail)
Dividends (Detail) - CAD | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Dividends [Line Items] | ||
Dividend declared for common share holders | CAD 124,831,000 | CAD 83,097,000 |
Cash dividend declared per common share (CAD per share) | CAD 0.4867 | CAD 0.3695 |
Series A Preferred Stock | ||
Dividends [Line Items] | ||
Dividends declared for preferred share holders | CAD 5,400,000 | CAD 5,400,000 |
Dividend declared per preferred share (CAD per share) | CAD 1.1250 | CAD 1.1250 |
Series D Preferred Stock | ||
Dividends [Line Items] | ||
Dividends declared for preferred share holders | CAD 5,000,000 | CAD 4,103,000 |
Dividend declared per preferred share (CAD per share) | CAD 1.2500 | CAD 1.0257 |
Related party transactions (Det
Related party transactions (Detail) | Jun. 28, 2015CAD | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Dec. 31, 2014CAD | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Emera | |||||||
Transactions with Third Party [Line Items] | |||||||
Amounts due from related party | $ | $ 491,000 | $ 0 | |||||
Emera | Energy Service | |||||||
Transactions with Third Party [Line Items] | |||||||
Inter-company sales | $ | $ 6,658,000 | $ 9,821,000 | |||||
Emera | Natural Gas | |||||||
Transactions with Third Party [Line Items] | |||||||
Purchases from related party | $ | $ 2,292,000 | $ 3,961,000 | |||||
Algonquin Power Systems Ltd. | |||||||
Transactions with Third Party [Line Items] | |||||||
Amounts due from related party | CAD 0 | CAD 47,000 | |||||
Equity Method Investee | |||||||
Transactions with Third Party [Line Items] | |||||||
Reimbursement of expenses | 2,021,000 | 189,000 | |||||
Algonquin Power Management Inc. | |||||||
Transactions with Third Party [Line Items] | |||||||
Aircraft usage shortfall fee | CAD 13,000 | ||||||
Cost in connection with aircraft | 507,000 | 721,000 | |||||
Base lease costs | 0 | 356,000 | |||||
Spouse of Senior Executive | |||||||
Transactions with Third Party [Line Items] | |||||||
Related party transactions, expenses paid | CAD 22,000 | CAD 192,000 |
Non-controlling Interests (Deta
Non-controlling Interests (Details) - CAD CAD in Thousands | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Noncontrolling Interest [Line Items] | |||
Total net earnings/(loss) attributable to noncontrolling interests | CAD (31,976) | CAD (22,186) | |
Other Noncontrolling Interests | |||
Noncontrolling Interest [Line Items] | |||
Total net earnings/(loss) attributable to noncontrolling interests | 1,966 | 1,529 | |
Class B Units | Noncontrolling Interest, Class B Partnership Units of SponsorCo | |||
Noncontrolling Interest [Line Items] | |||
Total net earnings/(loss) attributable to noncontrolling interests | 0 | 3,484 | |
Class A Units | Class A Partnership Units | |||
Noncontrolling Interest [Line Items] | |||
Total net earnings/(loss) attributable to noncontrolling interests | CAD (33,942) | CAD (27,199) | |
Wind Portfolio SponsorCo, LLC | Class B Units | |||
Noncontrolling Interest [Line Items] | |||
Ownership percentage | 100.00% |
Income taxes - Additional Infor
Income taxes - Additional Information (Detail) - CAD CAD in Thousands | Jun. 26, 2015 | Dec. 31, 2015 | Dec. 31, 2014 |
Income Tax Examination [Line Items] | |||
Canadian enacted statutory rate | 26.50% | 26.50% | |
Valuation allowance for deferred tax assets | CAD 17,478 | CAD 15,534 | |
Deferred taxes | 36,403 | CAD 13,133 | |
Deferred income taxes, undistributed earnings of foreign subsidiaries | CAD 64,678 | ||
Tax years 2009 to 2013 | Canada Revenue Agency | |||
Income Tax Examination [Line Items] | |||
Reduction in deferred tax assets | CAD 16,042 | ||
Reduction in deferred tax credits | 13,333 | ||
Deferred taxes | CAD 2,709 |
Income taxes - Provision for In
Income taxes - Provision for Income Taxes (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | ||
Expected income tax expense at Canadian statutory rate | CAD 34,516 | CAD 19,199 |
Increase (decrease) resulting from: | ||
Recognition of deferred credit | (2,448) | (5,763) |
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates | (3,855) | (1,677) |
Non-taxable corporate dividend | (3,311) | (2,618) |
Non-controlling interests share of income | 12,511 | 8,824 |
Production tax credit | (254) | (339) |
Allowance for equity funds used during construction | (935) | (746) |
State taxes | 733 | 604 |
Adjustment relating to prior periods | 2,431 | 0 |
CRA Settlement | 2,709 | 0 |
Other | 1,616 | (677) |
Income tax expense | CAD 43,713 | CAD 16,807 |
Income taxes - Income (Loss) Be
Income taxes - Income (Loss) Before Taxes (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items] | ||
Income/(loss) before taxes | CAD 130,249 | CAD 72,449 |
Canadian operations | ||
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items] | ||
Income/(loss) before taxes | 28,481 | 11,930 |
U.S. operations | ||
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items] | ||
Income/(loss) before taxes | CAD 101,768 | CAD 60,519 |
Income taxes - Income Tax Expen
Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Expenses [Line Items] | ||
Income tax expenses, current | CAD 7,310 | CAD 3,674 |
Income tax expenses, deferred | 36,403 | 13,133 |
Income tax expense | 43,713 | 16,807 |
Canada | ||
Income Tax Expenses [Line Items] | ||
Income tax expenses, current | 5,272 | 5,660 |
Income tax expenses, deferred | 1,959 | (3,538) |
Income tax expense | 7,231 | 2,122 |
United States | ||
Income Tax Expenses [Line Items] | ||
Income tax expenses, current | 2,038 | (1,986) |
Income tax expenses, deferred | 34,444 | 16,671 |
Income tax expense | CAD 36,482 | CAD 14,685 |
Income taxes - Tax Effect on Si
Income taxes - Tax Effect on Significant Portions of Deferred Tax Assets and Deferred Tax Liabilities (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax assets: | ||
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs | CAD 396,727 | CAD 319,056 |
Pension and OPEB | 57,969 | 54,458 |
Acquisition-related costs | 6,035 | 5,168 |
Environmental obligation | 28,230 | 28,555 |
Production tax credit | 3,027 | 2,098 |
Reserves not currently deductible | 2,503 | 2,315 |
Other | 4,970 | 3,988 |
Total deferred income tax assets | 499,461 | 415,638 |
Less valuation allowance | (17,478) | (15,534) |
Total deferred tax assets | 481,983 | 400,104 |
Deferred tax liabilities: | ||
Property, plant and equipment | (544,616) | (387,931) |
Intangible assets | (2,760) | (2,752) |
Outside basis in partnership | (32,221) | (15,194) |
Regulatory accounts | (28,270) | (49,399) |
Financial derivatives | (31,806) | (15,013) |
Total deferred tax liabilities | (639,673) | (470,289) |
Net deferred tax liabilities | (157,690) | (70,185) |
Deferred tax assets | 18,109 | 64,275 |
Deferred tax liabilities | CAD (175,799) | CAD (134,460) |
Income taxes - Non Capital Loss
Income taxes - Non Capital Losses Carry Forwards (Detail) CAD in Thousands | Dec. 31, 2015CAD |
Capital Loss Carryforwards [Line Items] | |
Non-capital loss carryforwards | CAD 967,499 |
Expires 2,016 | |
Capital Loss Carryforwards [Line Items] | |
Non-capital loss carryforwards | 0 |
2017 and onwards | |
Capital Loss Carryforwards [Line Items] | |
Non-capital loss carryforwards | CAD 967,499 |
Basic and diluted net earnin107
Basic and diluted net earnings per share - Schedule of Earnings per Share (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Class of Stock [Line Items] | ||
Net earnings attributable to shareholders of APUC | CAD 117,480 | CAD 75,701 |
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp. | 107,080 | 66,198 |
Discontinued operations | (1,032) | (2,127) |
Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted | CAD 108,112 | CAD 68,325 |
Weighted average number of shares | ||
Basic (in shares) | 253,172,088 | 213,953,870 |
Effect of dilutive securities (in shares) | 3,344,632 | 2,387,722 |
Diluted (in shares) | 256,516,720 | 216,341,592 |
Series A Preferred Stock | ||
Class of Stock [Line Items] | ||
Series A Preferred shares dividend | CAD 5,400 | CAD 5,400 |
Series D Preferred Stock | ||
Class of Stock [Line Items] | ||
Series A Preferred shares dividend | CAD 5,000 | CAD 4,103 |
Basic and diluted net earnin108
Basic and diluted net earnings per share - Additional Information (Detail) - shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Options and Convertible Debentures | ||
Class of Stock [Line Items] | ||
Anti-dilutive convertible debentures | 1,627,525 | 1,786,401 |
Segmented information - Results
Segmented information - Results of Operations and Assets for Segments (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue | ||
Revenue | CAD 1,027,855 | CAD 941,614 |
Fuel and power purchased | 376,873 | 420,886 |
Net revenue | 650,982 | 520,728 |
Operating expenses | 278,561 | 234,038 |
Administrative expenses | 40,675 | 34,692 |
Depreciation and amortization | 149,806 | 114,047 |
Gain on foreign exchange | (2,631) | (1,112) |
Operating income from continuing operations | 184,571 | 139,063 |
Interest expense | 65,993 | 62,418 |
Interest, dividend, equity and other income | (9,095) | (7,758) |
Other expenses (gain) | (2,576) | 11,954 |
Earnings (loss) before income taxes | 130,249 | 72,449 |
Property, plant and equipment | 3,873,684 | 3,278,422 |
Equity-method investees | 52,473 | 6,598 |
Total assets | 4,991,725 | 4,102,848 |
Capital expenditures | 204,195 | 432,373 |
Generation | ||
Revenue | ||
Revenue | 244,751 | 218,765 |
Fuel and power purchased | 27,990 | 39,264 |
Net revenue | 216,761 | 179,501 |
Operating expenses | 63,601 | 55,482 |
Administrative expenses | 10,822 | 13,457 |
Depreciation and amortization | 67,293 | 58,248 |
Gain on foreign exchange | 0 | 0 |
Operating income from continuing operations | 75,045 | 52,314 |
Interest expense | 29,395 | 33,868 |
Interest, dividend, equity and other income | (1,154) | (1,187) |
Other expenses (gain) | (5,623) | 48 |
Earnings (loss) before income taxes | 52,427 | 19,585 |
Property, plant and equipment | 1,895,617 | 1,687,465 |
Equity-method investees | 44,638 | 3,520 |
Total assets | 2,345,905 | 1,896,265 |
Capital expenditures | 55,992 | 201,063 |
Distribution | ||
Revenue | ||
Revenue | 783,104 | 722,849 |
Fuel and power purchased | 348,883 | 381,622 |
Net revenue | 434,221 | 341,227 |
Operating expenses | 213,750 | 178,248 |
Administrative expenses | 21,570 | 19,947 |
Depreciation and amortization | 82,513 | 53,671 |
Gain on foreign exchange | 0 | 0 |
Operating income from continuing operations | 116,388 | 89,361 |
Interest expense | 34,971 | 27,139 |
Interest, dividend, equity and other income | (3,974) | (3,369) |
Other expenses (gain) | 391 | 300 |
Earnings (loss) before income taxes | 85,000 | 65,291 |
Property, plant and equipment | 1,914,980 | 1,531,166 |
Equity-method investees | 769 | 500 |
Total assets | 2,532,894 | 2,098,244 |
Capital expenditures | 141,445 | 176,849 |
Corporate | ||
Revenue | ||
Revenue | 0 | 0 |
Fuel and power purchased | 0 | 0 |
Net revenue | 0 | 0 |
Operating expenses | 1,210 | 308 |
Administrative expenses | 8,283 | 1,288 |
Depreciation and amortization | 0 | 2,128 |
Gain on foreign exchange | (2,631) | (1,112) |
Operating income from continuing operations | (6,862) | (2,612) |
Interest expense | 1,627 | 1,411 |
Interest, dividend, equity and other income | (3,967) | (3,202) |
Other expenses (gain) | 2,656 | 11,606 |
Earnings (loss) before income taxes | (7,178) | (12,427) |
Property, plant and equipment | 63,087 | 59,791 |
Equity-method investees | 7,066 | 2,578 |
Total assets | 112,926 | 108,339 |
Capital expenditures | CAD 6,758 | CAD 54,461 |
Segmented information - Additio
Segmented information - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2015segmentcountry | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | ||
Number of business units | segment | 3 | |
Percentage of revenue contributed | 80.00% | |
Number of countries in which entity operates | country | 2 | |
Sales Revenue, Net | Hydro Quebec | ||
Segment Reporting Information [Line Items] | ||
Percentage of revenue contributed | 13.00% | 11.00% |
Sales Revenue, Net | Manitoba Hydro | ||
Segment Reporting Information [Line Items] | ||
Percentage of revenue contributed | 13.00% | 13.00% |
Sales Revenue, Net | PJM | ||
Segment Reporting Information [Line Items] | ||
Percentage of revenue contributed | 14.00% | 10.00% |
Sales Revenue, Net | ComEd | ||
Segment Reporting Information [Line Items] | ||
Percentage of revenue contributed | 11.00% | 10.00% |
Segmented information - Informa
Segmented information - Information on Operations by Geographic Area (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | ||
Revenue | CAD 1,027,855 | CAD 941,614 |
Property, plant and equipment | 3,873,684 | 3,278,422 |
Intangible assets | 77,963 | 54,011 |
Canada | ||
Segment Reporting Information [Line Items] | ||
Revenue | 86,977 | 92,267 |
Property, plant and equipment | 592,598 | 590,580 |
Intangible assets | 40,186 | 25,601 |
United States | ||
Segment Reporting Information [Line Items] | ||
Revenue | 940,878 | 849,347 |
Property, plant and equipment | 3,281,086 | 2,687,842 |
Intangible assets | CAD 37,777 | CAD 28,410 |
Commitments and contingencies -
Commitments and contingencies - Additional Information (Detail) - CAD | Oct. 21, 2011 | Dec. 31, 2015 | Dec. 31, 2012 |
Commitment And Contingencies [Line Items] | |||
Estimated capital repair expenditure | CAD 8,000,000 | ||
Period estimated capital repair expenditures for energy project will be incurred | 4 years | ||
Water Rights | |||
Commitment And Contingencies [Line Items] | |||
Water lease claim payment | CAD 5,400,000 | ||
Minimum potential unrecoverable loss | CAD 0 | ||
Maximum potential unrecoverable loss | CAD 6,800,000 | ||
Leases | |||
Commitment And Contingencies [Line Items] | |||
Claims paid to government of Quebec | CAD 1,884,000 |
Commitments and contingencie113
Commitments and contingencies - Estimates of Future Commitments (Detail) CAD in Thousands | Dec. 31, 2015CAD |
Commitments Disclosure [Line Items] | |
Year 1 | CAD 228,707 |
Year 2 | 150,358 |
Year 3 | 132,176 |
Year 4 | 135,206 |
Year 5 | 132,680 |
Thereafter | 706,930 |
Total | 1,486,057 |
Power purchase (i) | |
Commitments Disclosure [Line Items] | |
Year 1 | 82,403 |
Year 2 | 52,644 |
Year 3 | 55,599 |
Year 4 | 59,165 |
Year 5 | 59,791 |
Thereafter | 0 |
Total | 309,602 |
Gas supply and service agreements (ii) | |
Commitments Disclosure [Line Items] | |
Year 1 | 66,264 |
Year 2 | 46,673 |
Year 3 | 36,621 |
Year 4 | 35,482 |
Year 5 | 32,070 |
Thereafter | 82,509 |
Total | 299,619 |
Service agreements | |
Commitments Disclosure [Line Items] | |
Year 1 | 38,335 |
Year 2 | 38,151 |
Year 3 | 35,019 |
Year 4 | 35,734 |
Year 5 | 35,955 |
Thereafter | 518,193 |
Total | 701,387 |
Capital projects | |
Commitments Disclosure [Line Items] | |
Year 1 | 35,842 |
Year 2 | 7,571 |
Year 3 | 71 |
Year 4 | 71 |
Year 5 | 71 |
Thereafter | 18 |
Total | 43,644 |
Operating leases | |
Commitments Disclosure [Line Items] | |
Year 1 | 5,863 |
Year 2 | 5,319 |
Year 3 | 4,866 |
Year 4 | 4,754 |
Year 5 | 4,793 |
Thereafter | 106,210 |
Total | CAD 131,805 |
Changes in Non-Cash Operating I
Changes in Non-Cash Operating Items (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Disclosure Changes In Non Cash Operating Items [Abstract] | ||
Accounts receivable | CAD 6,715 | CAD (23,640) |
Natural gas in storage | 3,049 | (5,942) |
Supplies and consumable inventory | (2,968) | (3,861) |
Income taxes receivable | (2,529) | (189) |
Prepaid expenses | (7,833) | 827 |
Accounts payable | (18,261) | 54,299 |
Accrued liabilities | (28,495) | 32,520 |
Current income tax liability | 1,820 | (1,527) |
Net regulatory assets and liabilities | 37,353 | (54,277) |
Changes in non-cash operating items | CAD (11,149) | CAD (1,790) |
Financial instruments - Fair V
Financial instruments - Fair Value of Financial Instruments (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Level 1 | ||
Fair Value of Financial Instruments [Line Items] | ||
Long-term debt | CAD 511,829 | CAD 520,142 |
Total financial liabilities | 511,829 | 520,142 |
Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 126,468 | 41,339 |
Derivative financial instruments, assets | 4 | 0 |
Total financial assets | 126,472 | 41,339 |
Long-term debt | 1,035,517 | 843,792 |
Preferred shares, Series C | 17,303 | 18,209 |
Derivative financial instruments, liabilities | 114,812 | 45,271 |
Total financial liabilities | 1,167,632 | 907,272 |
Level 3 | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 0 | 0 |
Derivative financial instruments, assets | 88,357 | 42,470 |
Total financial assets | 88,357 | 42,470 |
Derivative financial instruments, liabilities | 446 | 0 |
Total financial liabilities | 446 | 0 |
Energy contracts | Designated as a hedge | Cash flow hedge | Level 3 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 88,357 | 41,966 |
Derivative financial instruments, liabilities | 446 | |
Energy contracts | Not designated as a hedge | Cash flow hedge | Level 3 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 504 | |
Cross currency swap | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 101,559 | |
Cross currency swap | Designated as a hedge | Net Investment Hedging | Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 101,559 | 36,276 |
Interest rate swaps | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 9,659 | |
Interest rate swaps | Designated as a hedge | Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 9,659 | 4,684 |
Interest rate swaps | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,383 | |
Interest rate swaps | Not designated as a hedge | Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,383 | |
Foreign exchange forward | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,918 | |
Foreign exchange forward | Not designated as a hedge | Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,918 | |
Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 2,122 | |
Commodity contracts for regulatory operations | Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 4 | |
Derivative financial instruments, liabilities | 1,676 | 2,928 |
Carrying amount | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 119,383 | 39,510 |
Derivative financial instruments, assets | 88,361 | 42,470 |
Total financial assets | 207,744 | 81,980 |
Long-term debt | 1,486,795 | 1,271,719 |
Preferred shares, Series C | 18,527 | 18,693 |
Derivative financial instruments, liabilities | 115,258 | 45,271 |
Total financial liabilities | 1,620,580 | 1,335,683 |
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 88,357 | 41,966 |
Derivative financial instruments, liabilities | 446 | |
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 504 | |
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 101,559 | 36,276 |
Carrying amount | Interest rate swaps | Designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 9,659 | 4,684 |
Carrying amount | Interest rate swaps | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,383 | |
Carrying amount | Foreign exchange forward | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,918 | |
Carrying amount | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 4 | |
Derivative financial instruments, liabilities | 1,676 | 2,928 |
Fair Value | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 126,468 | 41,339 |
Derivative financial instruments, assets | 88,361 | 42,470 |
Total financial assets | 214,829 | 83,809 |
Long-term debt | 1,547,346 | 1,363,934 |
Preferred shares, Series C | 17,303 | 18,209 |
Derivative financial instruments, liabilities | 115,258 | 45,271 |
Total financial liabilities | 1,679,907 | 1,427,414 |
Fair Value | Energy contracts | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 88,357 | 41,966 |
Derivative financial instruments, liabilities | 446 | |
Fair Value | Energy contracts | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 504 | |
Fair Value | Cross currency swap | Designated as a hedge | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 101,559 | 36,276 |
Fair Value | Interest rate swaps | Designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 9,659 | 4,684 |
Fair Value | Interest rate swaps | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,383 | |
Fair Value | Foreign exchange forward | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 1,918 | |
Fair Value | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 4 | |
Derivative financial instruments, liabilities | CAD 1,676 | CAD 2,928 |
Financial instruments - Additi
Financial instruments - Additional Information (Detail) $ in Thousands | Nov. 14, 2014CAD | Dec. 31, 2015CADCAD / MWh | Dec. 31, 2014CAD | Dec. 31, 2015USD ($)CAD / MWh | Jan. 31, 2014CAD | Dec. 31, 2013CAD |
Derivative [Line Items] | ||||||
Long-term debt | CAD 1,486,795,000 | CAD 1,271,719,000 | ||||
Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months | 14,975,000 | |||||
Other comprehensive income, foreign currency loss | 0 | (2,727,000) | ||||
Other comprehensive income, foreign currency translation adjustment loss | CAD (289,035,000) | (104,183,000) | ||||
Major customer revenue percentage | 80.00% | |||||
Revenue collection period | 45 days | |||||
Cash on hand | CAD 124,353,000 | |||||
Available for drawn on senior debt facilities | 580,901,000 | |||||
Utility Services | ||||||
Derivative [Line Items] | ||||||
Accounts receivable balances | $ | $ 91,308 | |||||
Generation | ||||||
Derivative [Line Items] | ||||||
Other comprehensive income, foreign currency translation adjustment loss | 68,195,000 | 28,537,000 | ||||
Bonds | Plan | ||||||
Derivative [Line Items] | ||||||
Debt instrument, term | 10 years | |||||
Long-term debt | CAD 135,000,000 | |||||
Senior Unsecured Notes | Generation | 4.82% Senior Unsecured Notes | ||||||
Derivative [Line Items] | ||||||
Debt instrument, face value | 150,000,000 | 150,000,000 | CAD 150,000,000 | |||
Senior Unsecured Notes | Generation | 4.65% Senior Unsecured Notes | ||||||
Derivative [Line Items] | ||||||
Debt instrument, face value | 200,000,000 | 200,000,000 | CAD 200,000,000 | |||
Interest rate swaps | ||||||
Derivative [Line Items] | ||||||
Derivative liability | CAD 9,659,000 | |||||
Interest rate swaps | Not designated as a hedge | ||||||
Derivative [Line Items] | ||||||
Fixed interest rate | 4.47% | 4.47% | ||||
Notional amount | CAD 58,791,000 | |||||
Derivative liability | 1,383,000 | |||||
Energy contracts | ||||||
Derivative [Line Items] | ||||||
Derivative, collateral held by third parties | 4,882,000 | 156,000 | ||||
Foreign exchange forward | Not designated as a hedge | ||||||
Derivative [Line Items] | ||||||
Notional amount | 85,812,000 | $ 63,400 | ||||
Cash flow hedge | Interest rate swaps | ||||||
Derivative [Line Items] | ||||||
Term of forward-starting interest rate swap | 10 years | |||||
Change in fair value recorded in OCI | CAD 4,974,000 | CAD 4,684,000 | ||||
Minimum | ||||||
Derivative [Line Items] | ||||||
Forward price | CAD / MWh | 18.39 | 18.39 | ||||
Maximum | ||||||
Derivative [Line Items] | ||||||
Forward price | CAD / MWh | 138.3 | 138.3 | ||||
Weighted Average | ||||||
Derivative [Line Items] | ||||||
Forward price | CAD / MWh | 39.98 | 39.98 | ||||
Red Lily | ||||||
Derivative [Line Items] | ||||||
Estimated discount rate used to measure fair value of conversion option | 9.00% | |||||
Derivative assets, fair value | ||||||
Fair Value | ||||||
Derivative [Line Items] | ||||||
Derivative liability | CAD 115,258,000 | CAD 45,271,000 | ||||
Fair Value | Interest rate swaps | Not designated as a hedge | ||||||
Derivative [Line Items] | ||||||
Derivative liability | CAD 1,383,000 | |||||
Fair Value | Foreign exchange forward | Not designated as a hedge | ||||||
Derivative [Line Items] | ||||||
Derivative liability | CAD 1,918,000 |
Financial instruments - Summar
Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail) | Dec. 31, 2015MMBTU |
Derivative [Line Items] | |
Commodity volumes, Gas | 1,498,597 |
Financial contracts Gas swaps | |
Derivative [Line Items] | |
Commodity volumes, Gas | 1,086,228 |
Gas options | |
Derivative [Line Items] | |
Commodity volumes, Gas | 412,369 |
Financial instruments - Impact
Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) CAD in Thousands, $ in Thousands | Dec. 31, 2015CAD | Dec. 31, 2015USD ($) | Dec. 31, 2014CAD | Dec. 31, 2014USD ($) |
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | CAD | CAD 245,315 | CAD 247,272 | ||
Regulatory liabilities, natural gas derivative contracts | CAD | CAD 175,347 | CAD 121,756 | ||
Gas swap contracts | ||||
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | $ 1,058 | $ 2,178 | ||
Regulatory liabilities, natural gas derivative contracts | 3 | 0 | ||
Gas options | ||||
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | 154 | 346 | ||
Regulatory liabilities, natural gas derivative contracts | $ 0 | $ 0 |
Financial instruments - Long-t
Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge | Dec. 31, 2015MWhCAD / MWh$ / MWh |
AESO | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | 49,135 |
Receive average prices (per MW-hr) | CAD / MWh | 68.56 |
PJM Western HUB | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | 801,098 |
Receive average prices (per MW-hr) | $ / MWh | 42.81 |
NI HUB | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | 3,419,634 |
Receive average prices (per MW-hr) | $ / MWh | 30.25 |
ERCOT North HUB | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | 3,997,509 |
Receive average prices (per MW-hr) | $ / MWh | 36.46 |
Financial instruments - Deriva
Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value Disclosures [Abstract] | ||
Effective portion of cash flow hedge, loss (gain) | CAD 21,932 | CAD (2,592) |
Amortization of cash flow hedge | (36) | (32) |
Loss (gain) reclassified from AOCI | (5,731) | 5,423 |
Loss (gain) reclassified from AOCI | 16,165 | 2,799 |
Less noncontrolling interest | 0 | 5,982 |
OCI attributable to shareholders of APUC | CAD 16,165 | CAD 8,781 |
Financial instruments - Effect
Financial instruments - Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized loss (gain) on derivative financial instruments | CAD (1,990) | CAD 3,046 |
Total realized loss (gain) on derivative financial instruments | 1,918 | 0 |
Ineffective portion of derivative financial instruments accounted for as hedges | 36 | 32 |
Loss (gain) on derivative financial instruments | 2,188 | (1,375) |
Gain (loss) on derivative instruments | (270) | 1,375 |
Not Designated as Hedging Instrument | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized loss (gain) on derivative financial instruments | 1,421 | 1,589 |
Total realized loss (gain) on derivative financial instruments | 919 | (1,665) |
Loss (gain) on derivative financial instruments not accounted for as hedges | 2,340 | (76) |
Not Designated as Hedging Instrument | Interest rate swaps | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized loss (gain) on derivative financial instruments | (1,383) | (1,797) |
Total realized loss (gain) on derivative financial instruments | 1,498 | 1,962 |
Not Designated as Hedging Instrument | Energy derivative contracts | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized loss (gain) on derivative financial instruments | 886 | 3,386 |
Total realized loss (gain) on derivative financial instruments | (579) | (3,627) |
Not Designated as Hedging Instrument | Foreign exchange forward | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized loss (gain) on derivative financial instruments | 1,918 | 0 |
Designated as Hedging Instrument | ||
Fair Value of Financial Instruments [Line Items] | ||
Ineffective portion of derivative financial instruments accounted for as hedges | CAD (2,610) | CAD 1,451 |
Financial instruments - Maximu
Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) - Dec. 31, 2015 CAD in Thousands, $ in Thousands | CAD | USD ($) |
Fair Value Disclosures [Abstract] | ||
Cash and cash equivalents and restricted cash | CAD 39,972 | $ 74,696 |
Accounts receivable | CAD 15,016 | 129,791 |
Allowance for doubtful accounts | (5,756) | |
Notes receivable | CAD 19,664 | 72,052 |
Maximum exposure to credit risk for financial instruments | CAD 74,652 | $ 270,783 |
Financial instruments - Liabil
Financial instruments - Liabilities Mature (Detail) - CAD CAD in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Long-term debt obligations | CAD 1,496,123 | |
Advances in aid of construction | 92,285 | |
Interest on long-term debt | 664,099 | |
Purchase obligations | 243,748 | |
Environmental obligation | 78,495 | CAD 72,594 |
Other obligations | 53,502 | |
Total obligations | 2,743,510 | |
Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 101,559 | |
Interest rate swaps | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 9,659 | |
Foreign exchange forward | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 1,918 | |
Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 2,122 | |
Due less than 1 year | ||
Derivative [Line Items] | ||
Long-term debt obligations | 8,945 | |
Advances in aid of construction | 1,347 | |
Interest on long-term debt | 74,324 | |
Purchase obligations | 243,748 | |
Environmental obligation | 5,435 | |
Other obligations | 12,808 | |
Total obligations | 355,238 | |
Due less than 1 year | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 4,828 | |
Due less than 1 year | Foreign exchange forward | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 1,918 | |
Due less than 1 year | Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 1,885 | |
Due 2 to 3 years | ||
Derivative [Line Items] | ||
Long-term debt obligations | 222,810 | |
Interest on long-term debt | 138,841 | |
Environmental obligation | 41,494 | |
Other obligations | 0 | |
Total obligations | 422,004 | |
Due 2 to 3 years | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 8,963 | |
Due 2 to 3 years | Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 237 | |
Due 4 to 5 years | ||
Derivative [Line Items] | ||
Long-term debt obligations | 187,582 | |
Interest on long-term debt | 117,328 | |
Environmental obligation | 1,753 | |
Other obligations | 0 | |
Total obligations | 314,171 | |
Due 4 to 5 years | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 7,508 | |
Due 4 to 5 years | Interest rate swaps | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 0 | |
Due after 5 years | ||
Derivative [Line Items] | ||
Long-term debt obligations | 1,076,786 | |
Advances in aid of construction | 90,938 | |
Interest on long-term debt | 333,606 | |
Environmental obligation | 29,813 | |
Other obligations | 40,694 | |
Total obligations | 1,652,097 | |
Due after 5 years | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | CAD 80,260 |
Subsequent event - Convertib124
Subsequent event - Convertible Unsecured Subordinated Debentures (Details) - Convertible Subordinated Debt - Subsequent Event | Mar. 09, 2016CAD | Mar. 01, 2016CADCAD / sharesCAD / instrument | Feb. 28, 2017 |
Subsequent Event [Line Items] | |||
Debt instrument, face value | CAD | CAD 1,150,000,000 | CAD 1,000,000,000 | |
Debt instrument, interest rate | 5.00% | ||
Debt instrument, convertible, price per instrument (CAD per debenture) | 1,000 | ||
Debt instrument, convertible, price per instrument paid at closing (CAD per debenture) | 333 | ||
Debt instrument, convertible, price per instrument outstanding (CAD per debenture) | 667 | ||
Proceeds from issuance of debt | CAD | CAD 150,000,000 | ||
Debt instrument, effective interest rate | 15.00% | 0.00% | |
Debt Instrument, convertible, conversion price (CAD per share) | CAD / shares | CAD 10.60 | ||
Threshold consecutive trading days | 20 days | ||
Percentage of weighted average trading price | 95.00% |