Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2017shares | |
Document Documentand Entity Information [Abstract] | |
Document Type | 40-F |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2017 |
Document Fiscal Year Focus | 2,017 |
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 | 431,765,935 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | CAD 54,550 | CAD 110,417 |
Accounts receivable, net (note 4) | 306,872 | 189,658 |
Fuel and natural gas in storage (note 1(h)) | 55,718 | 21,625 |
Supplies and consumables inventory | 56,546 | 15,568 |
Regulatory assets (note 7) | 83,508 | 48,440 |
Prepaid expenses | 38,896 | 26,562 |
Derivative instruments (note 25) | 20,196 | 76,631 |
Other assets (note 12) | 8,919 | 2,951 |
Assets, current, total | 625,205 | 491,852 |
Property, plant and equipment, net (note 5) | 7,909,493 | 4,889,946 |
Intangible assets, net (note 6) | 64,108 | 64,989 |
Goodwill (note 6) | 1,196,234 | 306,641 |
Regulatory assets (note 7) | 467,626 | 243,524 |
Derivative instruments (note 25) | 67,888 | 74,553 |
Long-term investments (note 8) | 84,467 | 105,433 |
Deferred income taxes (note 20) | 76,972 | 30,005 |
Restricted cash (note 1(f)) | 19,995 | 2,026,183 |
Other assets (note 12) | 21,647 | 16,334 |
Assets | 10,533,635 | 8,249,460 |
Current liabilities: | ||
Accounts payable | 150,426 | 90,592 |
Accrued liabilities | 351,441 | 308,318 |
Dividends payable (note 17) | 63,283 | 38,973 |
Regulatory liabilities (note 7) | 47,278 | 47,769 |
Long-term debt (note 9) | 15,511 | 10,075 |
Other long-term liabilities and deferred credits (note 13) | 57,586 | 43,157 |
Derivative instruments (note 25) | 17,721 | 4,178 |
Other liabilities | 4,359 | 3,487 |
Liabilities, current, total | 707,605 | 546,549 |
Long-term debt (note 9) | 3,847,785 | 3,903,340 |
Convertible debentures (note 14) | 1,218 | 358,619 |
Regulatory liabilities (note 7) | 677,778 | 134,965 |
Deferred income taxes (note 20) | 499,819 | 288,139 |
Derivative instruments (note 25) | 68,769 | 104,647 |
Pension and other post-employment benefits obligation (note 10) | 210,994 | 147,845 |
Other long-term liabilities (note 13) | 285,106 | 232,449 |
Preferred shares, Series C (note 11) | 17,396 | 17,552 |
Liabilities, noncurrent, total | 5,608,865 | 5,187,556 |
Redeemable non-controlling interest (note 19) | 52,128 | 29,434 |
Equity: | ||
Preferred shares (note 15(b)) | 213,805 | 213,805 |
Common shares (note 15(a)) | 3,713,037 | 1,972,203 |
Additional paid-in capital | 43,204 | 38,652 |
Deficit | (617,836) | (556,024) |
Accumulated other comprehensive income (note 16) | 56,820 | 254,927 |
Total equity attributable to shareholders of Algonquin Power & Utilities Corp. | 3,409,030 | 1,923,563 |
Non-controlling interests (note 19) | 756,007 | 562,358 |
Total equity | 4,165,037 | 2,485,921 |
Commitments and contingencies (note 23) | ||
Liabilities and equity, total | CAD 10,533,635 | CAD 8,249,460 |
Consolidated Statements of Oper
Consolidated Statements of Operations - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement [Abstract] | ||
Earnings Per Share, Diluted | CAD 0.47 | CAD 0.44 |
Revenue | ||
Regulated electricity distribution | CAD 989,221 | CAD 228,097 |
Regulated gas distribution | 493,208 | 405,735 |
Regulated water reclamation and distribution | 181,851 | 181,655 |
Non-regulated energy sales | 282,558 | 243,149 |
Other revenue | 30,971 | 37,382 |
Total revenue | 1,977,809 | 1,096,018 |
Expenses | ||
Operating expenses | 598,658 | 333,001 |
Regulated electricity purchased | 288,183 | 119,825 |
Regulated gas purchased | 184,523 | 142,003 |
Regulated water purchased | 12,310 | 12,227 |
Non-regulated energy purchased | 25,384 | 21,260 |
Administrative expenses | 64,466 | 46,349 |
Depreciation and amortization | 326,447 | 186,899 |
Loss (gain) on foreign exchange | 373 | (436) |
Costs and Expenses, Total | 1,500,344 | 861,128 |
Operating income | 477,465 | 234,890 |
Interest expense on long-term debt and others | 184,993 | 73,962 |
Interest expense on convertible debentures and amortization of acquisition financing (notes 9(b) and 14) | 17,638 | 57,630 |
Interest, dividend, equity and other income | (11,989) | (10,573) |
Other losses (gains) (note 23(a)) | 632 | (11,818) |
Acquisition-related costs | 62,777 | 12,028 |
Gain on derivative financial instruments (note 25(b)(iv)) | (2,626) | (15,849) |
Nonoperating Income (Expense) | 251,425 | 105,380 |
Earnings (loss) before income taxes | 226,040 | 129,510 |
Income tax expense (note 20) | ||
Current | 9,908 | 8,461 |
Deferred | 85,286 | 28,675 |
Income tax expense | 95,194 | 37,136 |
Net earnings | 130,846 | 92,374 |
Net effect of non-controlling interests (note 19) | 62,248 | 38,550 |
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp. | 193,094 | 130,924 |
Series A and D Preferred shares dividend (note 17) | 10,400 | 10,400 |
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp. | CAD 182,694 | CAD 120,524 |
Basic net earnings per share (CAD per share) | CAD 0.48 | CAD 0.44 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Net earnings | CAD 130,846 | CAD 92,374 |
Other comprehensive income (loss): | ||
Foreign currency translation adjustment, net of tax recovery of $219 and $nil, respectively (notes 1(v), 25(b)(iii) and 25(b)(iv)) | (256,067) | (67,855) |
Change in fair value of cash flow hedges, net of tax expense of $756 and $18,109, respectively (note 25(b)(ii)) | 1,909 | 26,754 |
Change in value of available-for-sale investments | (141) | 213 |
Change in pension and other post-employment benefits, net of tax expense of $717 and $1,433, respectively (note 10) | 525 | 2,252 |
Other comprehensive loss, net of tax | (253,774) | (38,636) |
Comprehensive (loss) income | (122,928) | 53,738 |
Comprehensive loss attributable to the non-controlling interests | (117,915) | (45,376) |
Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp. | CAD (5,013) | CAD 99,114 |
Consolidated Statements of Com5
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Foreign currency translation adjustment, tax recovery | CAD 219 | CAD 0 |
Change in fair value of cash flow hedge, tax expense | 756 | 18,109 |
Change in pension and other post-employment benefit, tax expense | CAD 717 | CAD 1,433 |
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, 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 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net earnings (loss) | 92,374 | 130,924 | (38,550) | |||||
Redeemable non-controlling interests not included in equity (note 19) | 4,952 | 4,952 | ||||||
Other comprehensive loss | (38,636) | (31,810) | (6,826) | |||||
Dividends declared and distributions to non-controlling interests | (129,622) | (125,696) | (3,926) | |||||
Dividends and issuance of shares under dividend reinvestment plan (note 15(a)(iii)) | 0 | 33,862 | (33,862) | |||||
Common shares issued upon conversion of subscription receipts | 0 | 110,503 | (110,503) | |||||
Common shares issued pursuant to share-based awards (note 15(c)) | 9,165 | 18,944 | (5,505) | (4,274) | ||||
Share-based compensation (note 15(c)) | 5,916 | 5,916 | ||||||
Contributions received from non-controlling interests (notes 3(c), 3(g) and 8(b)) | 12,752 | 12,752 | ||||||
Non-controlling interest of acquired operating entity | 237,156 | 0 | 0 | 237,156 | ||||
Ending Balance at Dec. 31, 2016 | 2,485,921 | 1,972,203 | 213,805 | CAD 0 | 38,652 | (556,024) | 254,927 | 562,358 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net earnings (loss) | 130,846 | 193,094 | (62,248) | |||||
Redeemable non-controlling interests not included in equity (note 19) | 13,400 | 13,400 | ||||||
Other comprehensive loss | (253,774) | (198,107) | (55,667) | |||||
Dividends declared and distributions to non-controlling interests | (210,494) | (205,439) | (5,055) | |||||
Dividends and issuance of shares under dividend reinvestment plan (note 15(a)(iii)) | 0 | 47,470 | (47,470) | |||||
Common shares issued pursuant to public offering, net of costs (note 15(a)(i)) | 558,083 | 558,083 | ||||||
Common shares issued upon conversion of convertible debentures (note 14) | 1,114,688 | 1,114,688 | ||||||
Common shares issued pursuant to share-based awards (note 15(c)) | 12,069 | 20,593 | (6,527) | (1,997) | ||||
Share-based compensation (note 15(c)) | 11,079 | 0 | 11,079 | 0 | ||||
Contributions received from non-controlling interests (notes 3(c), 3(g) and 8(b)) | 303,219 | 303,219 | ||||||
Ending Balance at Dec. 31, 2017 | CAD 4,165,037 | CAD 3,713,037 | CAD 213,805 | CAD 43,204 | CAD (617,836) | CAD 56,820 | CAD 756,007 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Operating Activities | ||
Net earnings from continuing operations | CAD 130,846 | CAD 92,374 |
Adjustments and items not affecting cash: | ||
Depreciation and amortization | 329,273 | 195,751 |
Deferred taxes | 85,286 | 28,675 |
Unrealized loss (gain) on derivative financial instruments | 1,764 | (18,689) |
Share-based compensation expense | 10,630 | 5,916 |
Cost of equity funds used for construction purposes | (3,014) | (2,774) |
Pension and post-employment contributions in excess of expense | (26,893) | (13,491) |
Non-cash revenue and other income | 0 | (10,467) |
Distributions received from equity investments, net of income | 3,141 | 653 |
Write-down of long-lived assets | 789 | 6,259 |
Changes in non-cash operating items (note 24) | (74,026) | 3,704 |
Net Cash Provided by (Used in) Operating Activities, Total | 457,796 | 287,911 |
Financing Activities | ||
Increase in long-term debt | 1,838,035 | 2,399,009 |
Decrease in long-term debt | (3,131,717) | (68,423) |
Issuance of convertible debentures, net of costs | 743,881 | 357,694 |
Cash dividends on common shares | (170,199) | (118,145) |
Dividends on preferred shares | (10,400) | (10,400) |
Contributions from non-controlling interests | 333,395 | 13,468 |
Production-based cash contributions from non-controlling interest | 10,622 | 9,454 |
Distributions to non-controlling interests | (4,135) | (4,307) |
Issuance of common shares, net of costs | 556,634 | 1,526 |
Proceeds from settlement of derivative assets | 48,381 | 0 |
Proceeds from exercise of share options | 12,761 | 18,461 |
Shares surrendered to fund withholding taxes on exercised share options | (4,401) | (5,218) |
Increase in other long-term liabilities | 33,030 | 6,486 |
Decrease in other long-term liabilities | (8,751) | (4,269) |
Net Cash Provided by (Used in) Financing Activities, Total | 247,136 | 2,595,336 |
Investing Activities | ||
Decrease (increase) in restricted cash | 2,011,204 | (2,007,732) |
Acquisitions of operating entities | (2,047,401) | (432,699) |
Divestiture of operating entity | 111,043 | 0 |
Additions to property, plant and equipment | (740,023) | (405,743) |
Increase in other assets | (9,122) | (20,501) |
Receipt of principal on notes receivable | 0 | 319,160 |
Increase in long-term investments | (82,449) | (347,901) |
Net Cash Provided by (Used in) Investing Activities, Total | (756,748) | (2,895,416) |
Effect of exchange rate differences on cash | (4,051) | (2,231) |
Decrease in cash and cash equivalents | (55,867) | (14,400) |
Cash and cash equivalents, beginning of year | 110,417 | 124,817 |
Cash and cash equivalents, end of year | 54,550 | 110,417 |
Supplemental disclosure of cash flow information: | ||
Cash paid during the year for interest expense | 198,045 | 131,783 |
Cash paid during the year for income taxes | 11,377 | 13,369 |
Non-cash financing and investing activities: | ||
Property, plant and equipment acquisitions in accruals | 141,708 | 146,301 |
Issuance of common shares under dividend reinvestment plan and share-based compensation plans | 51,178 | 35,409 |
Acquisition of equity investments in exchange for loan receivable and payable | 2,353 | 26,035 |
Convertible Debentures [Member] | ||
Non-cash financing and investing activities: | ||
Issuance of common shares upon conversion of subscription receipts | 1,102,304 | 0 |
Subscription receipts | ||
Non-cash financing and investing activities: | ||
Issuance of common shares upon conversion of subscription receipts | CAD 0 | CAD 110,503 |
Notes to the Consolidated Finan
Notes to the Consolidated Financial Statements | 12 Months Ended |
Dec. 31, 2017 | |
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's operations are organized across two primary North American business units consisting of the Liberty Power Group and the Liberty Utilities Group . The Liberty Power Group (" Liberty Power Group ") owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Liberty Utilities Group ("Liberty Utilities Group") owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations |
Significant accounting policies
Significant accounting policies | 12 Months Ended |
Dec. 31, 2017 | |
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(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(r)). (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. As at September 30 of each year, the Company assesses qualitative and quantitative 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. (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. 1. Significant accounting policies (continued) (d) Accounting for rate regulated operations (continued) 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 or 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”), the Regulator 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. As of December 31, 2016, restricted cash also included cash of U.S. $1,495,774 transfered to a paying agent for purposes of distribution to holders of common shares of The Empire District Electric Company and its subsidiaries (“Empire”) on January 1, 2017 (note 3(a)). Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash 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) Fuel and natural gas in storage Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, 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(d)) 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 net realizable value of fuel and 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 net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value. 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, together with the relevant authority, has authorized and committed to the funding of a 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. 2017 2016 Interest capitalized on non-regulated property $ 5,558 $ 3,259 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,673 1,167 Allowance for equity funds 3,014 2,774 Total $ 10,245 $ 7,200 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 2017 2016 2017 2016 Generation 3 - 60 3 - 60 33 32 Distribution 5 - 100 5 - 100 40 41 Equipment 5 - 50 5 - 50 13 11 The Company uses 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. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Liberty Utilities 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) Commonly owned facilities The Company owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60% with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company's share of operating costs are recognized in operating, maintenance and fuel expenditures excluding depreciation expense. As at December 31, 2017, the Company's consolidated balance sheet includes $833,578 of cost of plant in service of and $225,156 of accumulated depreciation related to commonly owned facilities. Total expenditures for the year ended December 31, 2017 were $99,930 . (l) 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. 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. (m) 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). 1. Significant accounting policies (continued) (m) Variable interest entities (continued) 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 $84,550 (2016 - $87,189 ) and $35,914 (2016 - $40,398 ), respectively. The portion of long-term debt which has recourse to the Company is $3,900 (2016 - $6,900 ). The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $22,743 (2016 - $29,132 ), operating expenses and amortization of $5,564 (2016 - $6,175 ) and interest expense of $3,573 (2016 - $4,064 ). (n) 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 and collectability of both the interest and principal are reasonably assured. 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. (o) Pension and other post-employment plans The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”), supplemental retirement program (“SERP”) 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, OPEB and SERP 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) (p) 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. (q) 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 additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares. (r) 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 ("LLC") and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units” or "Class A Equity Investors") which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLC and partnership's agreements have liquidation rights and priorities that are different from the underlying percentages ownership interests. In those situations, simply applying the percentage ownership interest to GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 19). The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Class A Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Class A Equity Investors' share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Class A Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments. 1. Significant accounting policies (continued) (r) Non-controlling interests (continued) 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. (s) 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. Qualifying renewable energy projects receive renewable energy credits ("REC") and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The REC and SREC can be traded and the owner of the REC or SREC can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at the time of generation. Any REC's or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses. 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 certain of the Company’s regulated utilities is subject to revenue decoupling mechanisms approved by their respective regulators 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 rates 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. 1. Significant accounting policies (continued) (t) Foreign currency translation APUC’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. (u) 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 (note 20). Investment tax credits for our rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Other income tax credits are treated as a reduction to 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. 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. (v) 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 on 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. 1. Significant accounting policies (continued) (v) Financial instruments and derivatives (continued) 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 |
Recently issued accounting pron
Recently issued accounting pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
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 2016-17 Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control. This update amends the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718), to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this update in the first quarter of 2017 had no material impact on the Company's consolidated financial statements. The Company continues to record the stock-based compensation expense adjusted for estimated forfeitures. The FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments, to clarify the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments in this Update is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships, to clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. 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 adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income to allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years . Early application is permitted in any interim period after issuance of the update. The Company is currently assessing the impacts of this update. The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early application is permitted in any interim period after issuance of the update. The Company is currently assessing the impacts of this update. The Company expects to early adopt this update on January 1, 2018. The FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting, to provide clarity and reduce both diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company applies the guidance in this update for modifications subsequent to December 15, 2017. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost, to improve the reporting of defined benefit pension cost and post-retirement benefit cost ("net benefit cost") in the financial statements. This update requires the service cost component to be reported in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update will also only allow the service cost component to be eligible for capitalization when applicable. The Company will adopt this guidance effective January 1, 2018. Following the effective date of this ASU, the Company expects its regulated operations to only capitalize the service costs component and therefore no regulatory to U.S. GAAP reporting differences are anticipated. The Company intends to apply the practical expedient for retrospective application on the statement of operations. The FASB issued ASU 2017-05 Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The update clarifies the scope of the standard as well as provides additional guidance on partial sales of nonfinancial assets. The update is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted however the update must be adopted at the same time as ASU 2014-09. No impact on the consolidated financial statements is expected from the adoption of this update. The FASB issued ASU 2017-04 Business Combinations (Topic 350): Intangibles - Goodwill and Other (Topic 350) Simplifying the Test for Goodwill Impairment. The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The update is intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. The amendments in the Update should be applied prospectively. The Company will follow the pronouncements of this Update after the effective date. The FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash to eliminate current diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. The Company currently present changes in restricted cash as investing activities. The adoption of this standard will change the presentation of restricted cash on the consolidated statement of cash flows. The FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. The new standard requires the recognition of current and deferred income taxes for an intra-entity transfer of an asset other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes on these transactions until the asset has been sold to an outside party. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. No impact on the consolidated financial statements is expected from the adoption of this Update. The FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments in order to eliminate current diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. No impact on the consolidated financial statements is expected from the adoption of this Update. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. Early adoption for fiscal years and interim periods beginning after December 15, 2018 is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this Update. 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 FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The FASB also voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures. The Company held training sessions with the finance team and is currently in the process of creating an inventory of its lease contracts and analyzing the terms and conditions under the requirements of this new standard. The Company continues to monitor FASB amendments to ASC Topic 842. 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 presentation of unrealized gains/ losses from the Company's available-for-sale investments will change on the consolidated statement of comprehensive income. Certain disclosures with regards to financial liabilities will change based on the updated requirements. The FASB issued a revenue recognition standard codified as ASC 606, Revenue from Contracts with Customers. This 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. The core principal of the accounting guidance is that an entity should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 is expected to require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This new revenue standard is 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 has not elected to early adopt. The Company has completed its impact assessment. At this point, the Company expects the adoption of Topic 606 will have an immaterial impact on the consolidated financial statements and the pattern of revenue recognition. The Company also evaluated the disclosure requirements and determined that the disaggregation of revenue information required by the new standard will not have a significant impact on the Company’s information gathering processes and procedures as the revenue information required by the standard is consistent with historical revenue information gathered by the Company for financial reporting purposes. The Company intends to adopt the new revenue recognition standard using the modified retrospective method. |
Business acquisitions and devel
Business acquisitions and development projects | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Business acquisitions and development projects | Business acquisitions and development projects (a) Acquisition of Empire On January 1, 2017, the Company completed the acquisition of Empire, a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. The purchase price of approximately U.S. $2,414,000 for the acquisition of Empire consists of cash payment to Empire shareholders of U.S. $34.00 per common share and the assumption of approximately U.S. $855,000 of debt. The cash payment was funded with the acquisition facility for an amount of U.S. $1,336,440 (note 9(b)), proceeds received from the initial instalment of convertible debentures (note 14) and existing credit facility. The costs related to the acquisition have been expensed through the consolidated statements of operations. The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at January 1, 2017 based on their fair values, using the exchange rate on that date of U.S. $1.00 = CAD $1.3427 . Working capital $ 55,441 Property, plant and equipment 2,764,441 Goodwill 1,010,273 Regulatory assets 318,130 Other assets 58,553 Long-term debt (1,218,563 ) Regulatory liabilities (195,489 ) Pension and other post-employment benefits (105,005 ) Deferred income tax liability, net (562,397 ) Other liabilities (102,759 ) Total net assets acquired $ 2,022,625 Cash and cash equivalent $ 2,338 Total net assets acquired, net of cash and cash equivalent $ 2,020,287 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies and cost savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Liberty Utilities Group segment. Property, plant and equipment, exclusive of computer software, are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of the Empire's assets is 39 years. The table below presents the consolidated pro forma revenue and net income for the year ended December 31, 2017 and 2016 , assuming the acquisition of Empire had occurred on January 1, 2016. Pro forma net income includes the impact of fair value adjustments incorporated in the preliminary purchase price allocation above and adjustments necessary to reflect the financing costs as if the acquisition had been financed on January 1, 2016. However, non-recurring acquisition-related expenses are excluded from net income. Year Ended December 31 2017 2016 Revenues $ 1,977,809 $ 1,908,340 Net earnings attributable to common shareholders $ 229,976 $ 213,983 3. Business acquisitions and development projects (continued) (a) Acquisition of Empire (continued) This pro forma information does not purport to represent what the actual results of operations of the Company would have been had the acquisition occurred on this date nor does it purport to predict the results of operations for future periods. (b) Investment in joint venture with Abengoa and investment in Atlantica On November 1, 2017, APUC entered into an agreement to create a joint venture ("AAGES") with Seville, Spain-based Abengoa, S.A ("Abengoa") to identify, develop, and construct clean energy and water infrastructure assets with a global focus. Concurrently with the creation of the AAGES joint venture, APUC entered into a definitive agreement to purchase from Abengoa a 25% equity interest in Atlantica Yield plc ("Atlantica") for a total purchase price of approximately U.S. $608,000 , based on a price of U.S. $24.25 per ordinary share of Atlantica plus a contingent payment of up to U.S. $0.60 per-share payable two years after closing, subject to certain conditions. The transaction is expected to close in the first quarter of 2018, subject to regulatory approvals and other closing conditions. (c) Great Bay Solar Project On August 12, 2015, the Company acquired rights to develop a 75 MWac solar project in Somerset County, Maryland. The project consists of four separate sites: as of December 31, 2017, two sites had been fully synchronized with the power grid, one site partially placed in service, with the remaining portion of the facility expected to be placed in service in Q1 2018. The Great Bay Solar Facility is controlled by a subsidiary of APUC (Great Bay Holdings, LLC). Approximately U.S. $59,000 of the permanent project financing will come from tax equity investors. Equity capital contribution of U.S. $42,750 was received in 2017 with the remaining expected to be received in early 2018. Through its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project. The Company accounts for this interest as "Non-controlling interest" on the consolidated balance sheets. (d) Acquisition of the St. Lawrence Gas Company, Inc. On August 31, 2017, the Company entered into a definitive agreement to acquire St. Lawrence Gas Company, Inc. ("SLG"). SLG is a rate-regulated natural gas distribution utility serving customers in northern New York state. The total purchase price for the transaction is U.S. $70,000 , less total third-party debt of SLG outstanding at closing, and subject to customary working capital adjustments. Closing of the transaction remains subject to regulatory approval and other closing conditions and is expected to occur in late 2018 or early 2019. (e) Approval to acquire the Perris Water Distribution System On August 10, 2017 the Company’s board approved the acquisition of two water distribution systems serving customers from the City of Perris, California. The anticipated purchase price of U.S. $11,500 is expected to be established as rate base during the regulatory approval process. The City of Perris residents voted to approve the sale on November 7, 2017. Liberty Utilities expects to file the advice letter to acquire the water utility with the California Public Utility Commission in Q1 2018 with approval expected in late 2018. (f) Luning Solar Facility Luning Utilities (Luning Holdings) LLC (the “Luning Holdings”) is owned by the Calpeco Electric System. The 50 MWac solar generating facility is located in Mineral County, Nevada. During 2016, a tax equity agreement was executed. The Class A partnership units are owned by a third-party tax equity investor who funded U.S. $7,826 as of December 31, 2016 and U.S. $31,212 on February 17, 2017. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Luning Solar project. During a six-month period in year 2022, the tax investor has the right to withdraw from Luning Holdings 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 (note 19). Redemption is not considered probable as of December 31, 2017. On February 15, 2017, as the Luning Solar Facility achieved commercial operation, Luning Holdings obtained control for a total purchase price of U.S. $110,856 . 3. Business acquisitions and development projects (continued) (f) Luning Solar Facility (continued) The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 198 Property, plant and equipment 145,045 Asset retirement obligation (714 ) Non-controlling interest (tax equity) (50,548 ) Total net assets acquired $ 93,981 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. (g) Bakersfield II Solar Facility On December 14, 2016, the Company completed construction and placed in service a 10 MWac solar powered generating facility located adjacent to the Company’s 20 MWac Bakersfield I Solar Facility in Kern County, California (“Bakersfield II Solar Facility”). Commercial operations as defined by the power purchase agreement was reached on January 11, 2017. The Bakersfield II Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield II Partnership”). The Class A partnership units are owned by a third-party tax equity investor who funded U.S. $2,454 on November 29, 2016 and approximately U.S. $9,800 on February 28, 2017. With its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project. The Company accounts for this interest as “Non-controlling interest” on the consolidated balance sheets. (h) Wind Turbine Components Purchase In 2016, the Company purchased approximately $75,000 of wind turbine components that will qualify between 500 MW and 700 MW of new wind powered projects for the full U.S. $0.023 /kWh renewable energy production tax credit under the safe harbor guidelines established by the U.S. Internal Revenue Service, provided that such projects are placed in service before the end of 2020. (i) Acquisition of Park Water System 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. The total purchase price for the Park Water System is $353,077 (U.S. $249,540 ), net of the debt assumed of U.S. $91,750 and is subject to certain closing adjustments. All costs related to the acquisition have been expensed in the consolidated statements of operations. At the time of acquisition, Park Water System owned and operated three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and western Montana. Those three utilities were named Park Water Company, Apple Valley Ranchos Water Co. and Mountain Water Company. Mountain Water was the subject of a condemnation lawsuit filed by the city of Missoula. On June 22, 2017, the city of Missoula took possession of Mountain Water’s assets (note 23(a)). 3. Business acquisitions and development projects (continued) (i) Acquisition of Park Water System (continued) The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 2,045 Property, plant and equipment 345,254 Notes receivable 1,781 Goodwill 210,463 Regulatory assets 54,548 Other assets 185 Long-term debt (146,727 ) Regulatory liabilities (3,758 ) Pension and OPEB (18,747 ) Deferred income tax liability, net (51,795 ) Other liabilities (40,172 ) Total net assets acquired $ 353,077 The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. Immaterial changes to the initial allocation were recorded during 2016. Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies and cost savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Liberty Utilities Group segment. Property, plant and equipment are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of the Park Water System assets is 40 years. The Park Water System contributed revenue of $91,817 (2016 - $96,695 ) and pre-tax net earnings of $17,620 (2016 - $25,374 ) to the Company’s consolidated financial results for the year ended December 31, 2017. |
Accounts receivable
Accounts receivable | 12 Months Ended |
Dec. 31, 2017 | |
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract] | |
Accounts receivable | Accounts receivable Accounts receivable as of December 31, 2017 include unbilled revenue of $98,214 ( 2016 - $57,822 ) from the Company’s regulated utilities. Accounts receivable as of December 31, 2017 are presented net of allowance for doubtful accounts of $6,968 ( 2016 - $7,064 ). |
Property, plant and equipment
Property, plant and equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, plant and equipment | Property, plant and equipment Property, plant and equipment consist of the following: 2017 Cost Accumulated depreciation Net book value Generation $ 2,988,569 $ 494,912 $ 2,493,657 Distribution 5,247,499 483,345 4,764,154 Land 89,935 — 89,935 Equipment and other 143,158 51,026 92,132 Construction in progress Generation 263,418 — 263,418 Distribution 206,197 — 206,197 $ 8,938,776 $ 1,029,283 $ 7,909,493 2016 Cost Accumulated Net book Generation $ 2,613,267 $ 419,227 $ 2,194,040 Distribution 2,638,488 462,454 2,176,034 Land 60,868 — 60,868 Equipment and other 139,961 44,700 95,261 Construction in progress Generation 197,405 — 197,405 Distribution 166,338 — 166,338 $ 5,816,327 $ 926,381 $ 4,889,946 Generation assets include cost of $142,789 ( 2016 - $142,246 ) and accumulated depreciation of $43,792 ( 2016 - $39,958 ) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $2,117 ( 2016 - $2,117 ). Distribution assets include cost of $ 2,234,243 and accumulated depreciation of $ 587,202 related to regulated generation and transmission assets. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return. For the year ended December 31, 2017, contributions received in aid of construction of $16,044 ( 2016 - $49,794 ) have been credited to the cost of the assets. The 2016 credit also includes Canadian renewable and conservation expense refundable tax credit for the St Damase wind facility in the amount of $14,086 . |
Intangible assets and goodwill
Intangible assets and goodwill | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible assets and goodwill | Intangible assets and goodwill Intangible assets consist of the following: 2017 Cost Accumulated amortization Net book value Power sales contracts $ 70,929 $ 46,263 $ 24,666 Customer relationships 33,619 11,085 22,534 Interconnection agreements 17,790 882 16,908 $ 122,338 $ 58,230 $ 64,108 6. Intangible assets and goodwill (continued) 2016 Cost Accumulated Net book Power sales contracts $ 72,207 $ 44,641 $ 27,566 Customer relationships 35,979 10,999 24,980 Interconnection agreements 13,000 — 557 12,443 $ 121,186 $ 56,197 $ 64,989 Estimated amortization expense for intangible assets for the next year is $3,540 , $3,390 in year two, $3,380 in year three, $3,040 in year four and $2,720 in year five. All goodwill pertains to the Liberty Utilities Group . Changes in goodwill are as follows: Balance, January 1, 2016 $ 110,493 Business acquisitions 210,463 Foreign exchange (14,315 ) Balance, December 31, 2016 $ 306,641 Business acquisitions (note 3(a)) 1,010,273 Divestiture of operating entity (note 23(a)) (35,107 ) Foreign exchange (85,573 ) Balance, December 31, 2017 $ 1,196,234 |
Regulatory matters
Regulatory matters | 12 Months Ended |
Dec. 31, 2017 | |
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. On January 1, 2017, the Company completed the acquisition of Empire, an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. Empire also provides regulated water utility distribution services to three towns in Missouri. The Empire District Gas Company, a wholly owned subsidiary, is engaged in the distribution of natural gas in Missouri. These businesses are subject to regulation by the Missouri Public Service Commission, the State Corporation Commission of the State of Kansas, the Corporation Commission of Oklahoma, the Arkansas Public Service Commission and the Federal Energy Regulatory Commission. In general, the commissions set rates at a level that allows the utilities to collect total revenues or revenue requirements equal to the cost of providing service, plus an appropriate return on invested capital. 7. Regulatory matters (continued) 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. The following regulatory proceedings were recently completed: Utility State Regulatory Proceeding Type Annual Revenue Increase U.S. $'000 Effective Date EnergyNorth Gas System New Hampshire GRC $6,750 Temporary increase effective July 1, 2017 Granite State Electric System New Hampshire General Rate Case ("GRC") $6,105 July 1, 2016 Calpeco Electric System California Post-Test Year Adjustment Mechanism $2,175 January 1, 2018 New England Gas System Massachusetts GRC $8,300 U.S. $7,800 effective March 1, 2016 U.S. $500 effective March 1, 2017 New England Gas System Massachusetts Gas System Enhancement Plan $2,928 May 1, 2017 Midstates Gas System Illinois GRC $2,200 June 7, 2017 Peach State Gas System Georgia GRAM $2,725 March 1, 2016 Bella Vista Water System Rio Rico Water/Sewer System Arizona GRC $1,935 November 1, 2016 CalPeco Electric System California GRC $8,318 January 1, 2016 Various $3,551 2016, 2017 & 2018 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2017 2016 Regulatory assets Environmental remediation (a) $ 103,761 $ 104,160 Pension and post-employment benefits (b) 132,615 75,527 Debt premium (c) 72,016 25,173 Fuel and commodity costs adjustment (d) 43,311 6,990 Rate adjustment mechanism (e) 44,523 40,602 Clean Energy and other customer programs (f) 25,820 2,106 Deferred construction costs (g) 17,994 — Asset retirement (h) 20,172 2,113 Income taxes (i) 45,847 10,182 Rate case costs (j) 11,660 8,572 Other 33,415 16,539 Total regulatory assets $ 551,134 $ 291,964 Less current regulatory assets (83,508 ) (48,440 ) Non-current regulatory assets $ 467,626 $ 243,524 Regulatory liabilities Income taxes (i) $ 402,868 $ 1,501 Cost of removal (k) 231,064 110,330 Rate-base offset (l) 16,577 20,946 Fuel and commodity costs adjustment (d) 29,535 34,012 Deferred compensation received in relation to lost production (m) 11,789 — Deferred construction costs - fuel related (g) 9,306 — Pension and post-employment benefits (b) 12,648 5,481 Other 11,269 10,464 Total regulatory liabilities $ 725,056 $ 182,734 Less current regulatory liabilities (47,278 ) (47,769 ) Non-current regulatory liabilities $ 677,778 $ 134,965 (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 U.S. $21,626 relates to an 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 service 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. The pension and post-employments benefits liability is related to tracking accounts pertaining primarily to Park Water Company. The amounts recorded in these accounts occur when actual expenses have been less than adopted and refunds are expected to occur in future periods. 7. Regulatory matters (continued) (c) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (d) Fuel and commodity costs adjustment The revenue from the utilities includes a component which is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas 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 electricity and natural gas 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 25(b)(i)) are recoverable through the commodity costs adjustment. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water 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 to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. (f) Clean Energy and other customer programs The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. (g) Deferred construction costs Deferred construction costs reflects deferred construction costs and fuel related costs of specific generating facilities of Empire. These amounts are being recovered over the life of the plants. (h) Asset retirement The costs of retirement of assets are expected to be recovered through rates as well as the on-going liability accretion and asset depreciation expense. (i) Income taxes The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. The Tax Cuts and Jobs Act ("the Act") was enacted on December 22, 2017. Among other provisions, the Act reduces the corporate income tax rate from 35% to 21%. A reduction of regulatory asset and an increase to regulatory liability was recorded for excess deferred taxes probable of being refunded to customers of $411,409 . (j) 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. (k) 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. (l) Rate-base offset The regulators imposed a rate-base offset that will reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of 10-16 years. 7. Regulatory matters (continued) (m) Deferred compensation received in relation to lost production The regulatory liability for deferred compensation received from lost production represents Empire's refund from Southwest Power Administration for lost revenues at one of its generating facilities. These costs are being amortized over the period approved by state regulators. 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 generally earns carrying charges on the regulatory balances related to commodity cost adjustment, retroactive rate adjustments and rate case costs. |
Long-term investments
Long-term investments | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Long Term Investments And Notes Receivable [Abstract] | |
Long-term investments | Long-term investments Long-term investments consist of the following: 2017 2016 Equity-method investees Red Lily I Wind Facility (a) $ 22,799 $ 23,504 Deerfield Wind Project (b) — 34,727 Amherst Island Wind Project (c) 11,191 558 Other 6,489 5,630 $ 40,479 $ 64,419 Notes receivable Development loans (d) $ 37,710 $ 32,125 Other 4,163 6,058 41,873 38,183 Available-for-sale investment — 169 Other investments 2,115 2,662 Total long-term investments $ 84,467 $ 105,433 (a) Red Lily I Wind Facility Up to April 12, 2016, the Red Lily I Partnership (the “Partnership”) was 100% owned by an independent investor. APUC provided operation and supervision services to the Red Lily I project ("Red Lily I Wind Facility"), a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company’s investment in the Red Lily I Wind Facility up to that date was in the form of subordinated debt facilities of the Partnership. Effective April 12, 2016, the Company exercised its option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its subordinated loans. The amount by which the carrying value of the Company's investment exceeds the Company's proportionate share of the Partnership's net assets is not material. Due to certain participating rights being held by the minority investor, the decisions which most significantly impact the economic performance of Red Lily I require unanimous consent. As such, APUC is deemed, under U.S. GAAP, to not have control over the Partnership. As APUC exercises significant influence over operating and financial policies of Red Lily I, the Company accounts for the Partnership using the equity method. The Red Lily I Wind Facility contributed equity income of $2,776 (2016 - $ 1,288 ) to the Company's consolidated financial results for the year ended December 31, 2017. 8. Long-term investments (continued) (b) Deerfield Wind Project 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. On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo and obtained control of the facility. Upon acquisition of the initial 50% equity interest of Deerfield SponsorCo, the two members each contributed U.S. $1,000 to the capital of Deerfield SponsorCo. On October 12, 2016, third-party construction loan financing was provided to the Deerfield Wind Project in the amount of U.S. $262,900 and a tax equity agreement was executed. Concurrently, each member contributed another U.S. $19,891 to the capital of Deerfield SponsorCo. Construction was completed during the first quarter of 2017 and sale of power to the utility under the power purchase agreement started on February 21, 2017. The interest capitalized during the year ended December 31, 2017 to the investment while the Deerfield Wind Project was under construction amounts to $nil (2016 - $6,072 ). On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo for U.S. $21,585 and as a result, obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting which requires that the fair value of assets acquired and liabilities assumed in the subsidiary be recognized on the consolidated balance sheet as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(d)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of $nil was recorded on acquisition. On May 10, 2017, tax equity funding of U.S. $166,595 was received. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working Capital $ (14,551 ) Property, plant and equipment 442,086 Construction loan (352,666 ) Asset retirement obligation (2,816 ) Deferred revenue (1,556 ) Deferred tax liability (1,979 ) Net assets acquired $ 68,518 Cash and cash equivalent $ 4,183 Net assets acquired, net of cash and cash equivalent $ 64,335 (c) Amherst Island Wind Project Windlectric Inc. ("Windlectric") owns a 75 MW construction-stage wind development project (“Amherst Island Wind Project”) in the province of Ontario. On December 20, 2016, Windlectric, a wholly owned subsidiary of the Company at the time, issued fifty percent of its common shares for $50 to a third party and as a result is no longer controlled by APUC. The Company holds an option to acquire the remaining common shares at a fixed price any time prior to January 15, 2019. Windlectric is considered a VIE namely due to the low level of equity at risk at this point. The Company is not considered the primary beneficiary of Windlectric as the two shareholders have joint control and all decisions must be unanimous. As such, on the transaction date, the Company deconsolidated the assets and liabilities of Windlectric and recorded its retained non-controlling investment in equity and notes receivable and payable at fair value. A net gain of nil was recorded on deconsolidation. The Company is accounting for its investment in the joint venture under the equity method. The interest capitalized during the year end ed December 31, 2017 to the investment while the Amherst Island Wind Project is under construction amounts to $1,447 (2016 - $491 ). As at December 31, 2017, the third-party construction debt of the joint venture was $133,765. 8. Long-term investments (continued) (c) Amherst Island Wind Project (continued) As of December 31, 2017, the Company’s maximum exposure to loss of $289,374 is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(d). (d) Development loans The Company entered into committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide 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 equity investees' wind projects. As at December 31, 2017 , the Company has a loan and credit support facility with Windlectric of $37,710 (2016 - $29,723 ). The loan to Windlectric bears interest at an annual rate of 10% on outstanding principal amount and matures on December 31, 2019. The letters of credit are charged an annual fee of 2% on their stated amount. As of December 31, 2017, the following credit support was issued by the Company on behalf of Windlectric: $72,068 letters of credit and guarantees of obligations to the utilities under the PPAs; a guarantee of the obligations under the wind turbine, transmission line, transformer, and other supply agreements; a guarantee of the obligations under the engineering, procurement, and construction management agreements. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at $2,449 using a probability weighted discounted cash flow (level 3). Following acquisition of control of Deerfield SponsorCo (note 8(b)) and Odell SponsorCo LLC (note 8(e)(i)), amounts advanced to the wind project are eliminated on consolidation. The effects of foreign currency exchange rate fluctuations on these advances of a long-term investment nature are recorded in other comprehensive income from the date of acquisition. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures. (e) 2016 transactions i. Odell Wind Facility Up to September 15, 2016, the Company held a 50% equity interest in Odell SponsorCo LLC, which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Facility”) in the state of Minnesota. On September 15, 2016, the Company acquired the remaining 50% interest in Odell SponsorCo LLC for U.S. $26,500 and as a result, obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting, which requires, that the fair value of assets acquired, liabilities assumed and non-controlling interest in the subsidiary, be recognized on the consolidated balance sheets as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(d)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of nil was recorded on acquisition. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 11,836 Property, plant and equipment 469,222 Asset retirement obligation (4,812 ) Deferred tax liability (4,273 ) Non-controlling interest (tax equity investors) (237,156 ) Net assets $ 234,817 ii. Natural gas pipeline developments During 2016, APUC wrote off an amount of $6,367 representing the total value of its equity interest in the natural gas development projects as both projects have been canceled by the developer. |
Long-term debt
Long-term debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-term debt | Long-term debt Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value 2017 2016 Senior Unsecured Revolving Credit Facilities (a) — 2018-2022 N/A $ 65,017 $ 242,947 Senior Unsecured Bank Credit Facilities (b) — 2018-2019 N/A 169,343 2,140,122 Commercial Paper (c) 2019 N/A 6,994 — Canadian Dollar Borrowings Senior Unsecured Notes (d) 4.61 % 2018-2027 $ 785,669 781,833 487,389 Senior Secured Project Notes 10.27 % 2020-2027 $ 33,568 33,507 35,600 U.S. Dollar Borrowings Senior Unsecured Notes (e) 4.09 % 2020-2047 US$ 1,225,000 1,527,726 700,600 Senior Unsecured Utility Notes (f) 5.98 % 2020-2035 US$ 227,000 309,309 174,206 Senior Secured Utility Bonds (g) 4.95 % 2018-2044 US$ 752,500 969,567 132,551 $ 3,863,296 $ 3,913,415 Less: current portion (15,511 ) (10,075 ) $ 3,847,785 $ 3,903,340 Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized 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. Short-term obligations of $264,214 for which the maturity has been extended beyond 12 months subsequent to the end of the year or that are expected to be refinanced using the long-term credit facilities are presented as long-term debt. Recent financing activities: (a) Senior unsecured revolving credit facilities On September 20, 2017, the Company amended the terms of its $65,000 senior unsecured revolving bank credit facility to increase the commitments to $165,000 and extend the maturity from November 19, 2017 to November 19, 2018. As at December 31, 2017, the Liberty Utilities Group 's committed bank lines consisted of a U.S. $200,000 senior unsecured revolving credit facility ("Liberty Credit Facility") and a U.S. $200,000 revolving credit facility at Empire ("Empire Credit Facility") assumed in connection with the acquisition of Empire (note 3(a)). Subsequent to year-end on February 23, 2018, the Liberty Utilities Group ' increased commitments under the Liberty Credit Facility to U.S. $500,000 and extended the maturity to February 23, 2023. Concurrent with the amendment to the Liberty Credit Facility, the Liberty Utilities Group closed the Empire Credit Facility. On October 6, 2017, the Liberty Power Group amended the terms of its $350,000 senior unsecured revolving bank credit facility to increase the commitments to U.S. $500,000 and extended the maturity from July 31, 2019 to October 6, 2022. On October 6, 2017, the St. Damase Wind Facility entered into a $4,000 committed revolving credit facility. The facility matures on October 6, 2020 and is guaranteed by the Liberty Power Group. The facility replaces borrowings that were previously drawn under the Liberty Power Group’s senior unsecured revolving credit facility. As at December 31, 2017, $3,900 had been drawn on the facility. 9. Long-term debt (continued) (a) Senior unsecured revolving credit facilities (continued) Liberty Power had a $150,000 bilateral revolving credit facility with a maturity date of August 19, 2018. Concurrent with the expansion of the Liberty Power Credit Facility, the Liberty Power Group closed the bilateral credit facility on October 6, 2017. On December 31, 2017, the Liberty Power Group had an extendible one -year letter of credit facility agreement. The facility provides for issuances of letters of credit up to a maximum of $50,000 and U.S. $30,000 . Subsequent to year-end, on February 16, 2018, the Liberty Power Group 's increased availability under its revolving letter of credit facility to U.S. $200,000 and extended the maturity to January 31, 2021. As part of the Park Water System's acquisition on January 8, 2016 (note 3(i)), the Company assumed U.S. $4,250 of debt outstanding under its revolving credit facilities. Shortly after the closing of the acquisition, the Park Water System repaid and closed the revolving credit facilities. (b) Senior unsecured bank credit facilities On December 21, 2017, the Company entered into a U.S. $600,000 term credit facility with two Canadian banks maturing on December 21, 2018. On March 7, 2018 the company drew U.S. $600,000 under this facility. On December 30, 2016, in connection with the acquisition of Empire (note 3(a)), the Company drew U.S. $1,336,440 from the Acquisition Facility it obtained in 2016. The funds drawn were transferred to a paying agent on December 30, 2016 for purposes of distribution to holders of the common shares of Empire (note 3(a)) on January 1, 2017. The total amount of cash held by the paying agent of U.S. $1,495,774 is comprised of this Acquisition Facility draw of U.S. $1,336,440 and cash proceeds received from the initial instalment of convertible debentures (note 14) and is presented as restricted cash on the consolidated balance sheets. Following receipt of the Final Instalment from the convertible debentures on February 7, 2017 (note 14) and the senior notes financing on March 24, 2017 (note 9(d)), the Company fully repaid the Acquisition Facility. On January 4, 2016, the Company entered into a U.S. $235,000 term credit facility with two U.S. banks. On March 24, 2017, the Company repaid U.S. $100,000 of borrowings under the Corporate Term Credit Facility with proceeds from the closing of the U.S. $750,000 senior unsecured notes (notes 9(e)). In October 2017, the Company extended the maturity on its Corporate Term Credit Facility to July 5, 2019. As part of the Park Water System's acquisition on January 8, 2016 (note 3(i)), the Company assumed U.S. $22,500 of debt outstanding under a non-revolving term credit facility. In June 2017, this debt was fully repaid and closed. (c) Commercial Paper In connection with the acquisition of Empire (note 3(a)), the Company assumed a short-term U.S. $150,000 commercial paper program. (d) Canadian dollar senior unsecured notes On January 17, 2017, the Liberty Power Group issued $300,000 senior unsecured debentures bearing interest at 4.09% and with a maturity date of February 17, 2027. The debentures were sold at a price of $99.929 per $100.00 principal amount. In September 2017, the Company acquired an investment in an equity-investee in exchange for a note payable to the other partner of $669 . Repayment of the note is expected in 2019. (e) U.S. dollar senior unsecured notes On March 24, 2017, the Liberty Utilities Group 's debt financing entity issued U.S. $750,000 senior unsecured notes in six tranches. The proceeds were applied to repay the Acquisition Facility (note 9(b)) and other existing indebtedness. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0% . In anticipation of this financing, the Liberty Utilities Group had entered into forward contracts to lock in the underlying U.S. Treasury interest rates. Considering the effect of the hedges, the effective weighted average rate paid by the Liberty Utilities Group will be approximately 3.6% . 9. Long-term debt (continued) (f) U.S. dollar senior unsecured utility notes On February 8, 2017, the U.S. $707 Bella Vista Water unsecured notes were fully repaid. On January 1, 2017, in connection with the acquisition of Empire (note 3(a)), the Company assumed U.S. $102,000 in unsecured utility notes. The notes consist of two tranches, with maturities in 2033 and 2035 with coupons at 6.7% and 5.8% . (g) U.S. dollar senior secured utility bonds On January 1, 2017 in connection with the acquisition of Empire (note 3(a)), the Company assumed U.S. $733,000 in secured utility notes. The bonds are secured by a first mortgage indenture and consist of ten tranches with maturities ranging between 2018 and 2044 with coupons ranging from 3.58% to 6.82% . In June 2017, outstanding bonds payable for the Park Water systems in the amount of U.S. $63,000 were repaid using proceeds from the Mountain Water condemnation discussed in note 23(a). The Company had assumed the U.S. $65,000 of debt outstanding in connection with the acquisition of Park Water in 2016 (note 3(i)). (h) U.S. dollar senior secured project notes On March 14, 2017, in connection with the acquisition of Deerfield SponsorCo (note 8(b)), the Company assumed U.S. $262,219 in construction loan. The loans bear interest at an annual rate of 2.33% on any outstanding principal amount. On May 10, 2017, the construction loan was repaid from proceeds received from tax equity (note 8(b)) and cash contributions from APUC. As of December 31, 2017 , the Company had accrued $41,479 in interest expense ( 2016 - $27,225 ). Interest expense on the long-term debt in 2017 was $185,339 ( 2016 - $87,143 ). Principal payments due in the next five years and thereafter are as follows: 2018 2019 2020 2021 2022 Thereafter Total $ 279,724 $ 179,107 $ 391,025 $ 152,626 $ 492,343 $ 2,331,327 $ 3,826,152 |
Pension and other post-retireme
Pension and other post-retirement benefits | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [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 2017 were $ 9,387 ( 2016 - $5,223 ). In conjunction with the utility acquisitions, the Company assumes defined benefit pension, supplemental executive retirement plans 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. During 2016, the Company permanently froze the accrual of retirement benefits for participants under certain existing plans. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. 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 2017 2016 2017 2016 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 331,934 $ 269,382 $ 83,097 $ 76,565 Projected benefit obligation assumed from business combination 344,383 63,811 131,263 9,749 Modifications to pension plan — (2,754 ) — (1,235 ) Service cost 17,869 8,435 6,280 2,916 Interest cost 27,346 13,029 8,621 3,525 Actuarial (gain) loss 49,785 6,773 13,321 (2,870 ) Contributions from retirees — — 2,364 547 Gain on curtailment (1,129 ) — (6 ) — Benefits paid (64,605 ) (15,845 ) (8,092 ) (3,230 ) Gain on foreign exchange (48,546 ) (10,897 ) (14,834 ) (2,870 ) Projected benefit obligation, end of year $ 657,037 $ 331,934 $ 222,014 $ 83,097 Change in plan assets Fair value of plan assets, beginning of year 236,369 176,171 29,139 18,149 Plan assets acquired in business combination 247,741 44,258 122,900 10,563 Actual return on plan assets 82,096 17,221 25,612 1,854 Employer contributions 38,833 21,776 2,683 2,317 Benefits paid (64,605 ) (15,845 ) (5,901 ) (2,683 ) Loss on foreign exchange (33,686 ) (7,212 ) (10,737 ) (1,061 ) Fair value of plan assets, end of year $ 506,748 $ 236,369 $ 163,696 $ 29,139 Unfunded status $ (150,289 ) $ (95,565 ) $ (58,318 ) $ (53,958 ) Amounts recognized in the consolidated balance sheets consists of: Non-current assets — — 4,938 — Current liabilities (1,080 ) (436 ) (1,471 ) (1,242 ) Non-current liabilities (149,209 ) (95,129 ) (61,785 ) (52,716 ) Net amount recognized $ (150,289 ) $ (95,565 ) $ (58,318 ) $ (53,958 ) The accumulated benefit obligation for the pension plans was $614,840 and $317,025 as of December 31, 2017 and 2016 , respectively. On June 22, 2017, all Mountain Water employees were terminated as a result of the condemnation of the Mountain Water assets to the city of Missoula (note 23(a)). The pension and OPEB obligations of these employees remain with the Company. The assets and projected benefit obligations of the plans were revalued at June 30, 2017 and resulted in an actuarial gain of U.S. $2,354 recorded in other comprehensive income and a curtailment gain of U.S. $853 recorded against the loss on long-lived assets. 10. Pension and other post-employment benefits (continued) (a) Net pension and OPEB obligation (continued) During 2016, the Company permanently froze the accrual of retirement benefits for participants under certain of the existing plans. The plan amendments resulted in a decrease to the projected benefit obligation of U.S. $2,217 which is recorded as a prior service credit in OCI. In conjunction with the plan amendments, the assets and projected benefit obligations of amended plans were revalued at the closest month-end date which resulted in an actuarial loss of U.S. $8,204 recorded in OCI. Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2016 $ 29,461 $ (4,970 ) $ (2,338 ) $ — Additions to AOCI 4,479 (2,754 ) (3,242 ) (1,235 ) Amortization in current period (1,965 ) 765 (80 ) 347 Balance at December 31, 2016 $ 31,975 $ (6,959 ) $ (5,660 ) $ (888 ) Additions to AOCI (3,716 ) — (4,276 ) — Reclassification to regulatory accounts 1,584 — 4,902 — Amortization in current period (1,290 ) 868 321 365 Balance at December 31, 2017 $ 28,553 $ (6,091 ) $ (4,713 ) $ (523 ) Expected amortization in 2018 $ (451 ) $ 781 $ 214 $ 328 (b) Assumptions Weighted average assumptions used to determine net benefit cost for 2017 and 2016 were as follows: Pension benefits OPEB 2017 2016 2017 2016 Discount rate 4.01 % 4.16 % 4.12 % 4.23 % Expected return on assets 7.01 % 6.41 % 3.88 % 5.50 % Rate of compensation increase 3.00 % 3.00 % N/A N/A Health care cost trend rate Before Age 65 6.25 % 6.50 % Age 65 and after 6.25 % 6.50 % Assumed Ultimate Medical Inflation Rate 4.75 % 4.75 % Year in which Ultimate Rate is reached 2023 2023 10. Pension and other post-employment benefits (continued) (b) Assumptions (continued) Weighted average assumptions used to determine net benefit obligation for 2017 and 2016 were as follows: Pension benefits OPEB 2017 2016 2017 2016 Discount rate 3.43 % 3.95 % 3.60 % 4.04 % Rate of compensation increase 3.00 % 3.00 % N/A N/A Health care cost trend rate Before Age 65 6.25 % 6.25 % Age 65 and after 6.25 % 6.25 % Assumed Ultimate Medical Inflation Rate 4.75 % 4.75 % Year in which Ultimate Rate is reached 2024 2023 The mortality assumption for December 31, 2017 was updated to the projected generationally scale MP-2017, adjusted to reflect the ultimate improvement rates in the 2017 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 2017 is as follows. The effects on total service and interest cost of a one percent change in HCCTR excludes the effects of Empire. 2017 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 38,047 Total service and interest cost 959 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (30,057 ) Total service and interest cost (765 ) 10. Pension and other post-employment benefits (continued) (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 2017 2016 2017 2016 Service cost $ 17,869 $ 8,435 $ 6,280 $ 2,916 Interest cost 27,346 13,029 8,621 3,525 Expected return on plan assets (32,244 ) (14,854 ) (8,312 ) (1,265 ) Amortization of net actuarial loss (gain) 1,480 1,965 (299 ) 80 Amortization of prior service credits (808 ) (765 ) (339 ) (347 ) Gain on curtailments and settlements (1,394 ) — (6 ) — Amortization of regulatory assets/liability 15,179 4,698 507 1,471 Net benefit cost $ 27,428 $ 12,508 $ 6,452 $ 6,380 (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 70 % 49% - 79% Debt securities 30 % 21% - 51% Other — % — % The fair values of investments as of December 31, 2017 , by asset category, are as follows: Asset Class Level 1 Percentage Equity securities 505,219 72 % Debt securities 164,281 27 % Other 945 — % As of December 31, 2017 , the funds do not hold any material investments in APUC. (e) Cash flows The Company expects to contribute $26,686 to its pension plans and $4,898 to its post-employment benefit plans in 2018. The expected benefit payments over the next ten years are as follows: 2017 2018 2019 2020 2021 2022-2026 Pension plan $ 43,445 $ 39,037 $ 40,132 $ 45,060 $ 45,108 $ 236,821 OPEB 7,353 7,989 8,845 9,425 10,093 58,844 |
Mandatorily redeemable Series C
Mandatorily redeemable Series C preferred shares | 12 Months Ended |
Dec. 31, 2017 | |
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: 2018 $ 1,068 2019 1,282 2020 1,344 2021 1,364 2022 1,390 Thereafter to 2031 15,761 Redemption amount 5,340 27,549 Less amounts representing interest (9,085 ) 18,464 Less current portion (1,068 ) $ 17,396 |
Other assets
Other assets | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other assets | Other assets Other assets consist of the following: 2017 2016 Income tax receivable $ 7,485 $ 2,951 Deferred financing costs 4,448 10,198 Other 18,633 6,136 30,566 19,285 Less current portion (8,919 ) (2,951 ) $ 21,647 $ 16,334 |
Other long-term liabilities and
Other long-term liabilities and deferred credits | 12 Months Ended |
Dec. 31, 2017 | |
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: 2017 2016 Advances in aid of construction (a) $ 78,636 $ 105,191 Environmental remediation obligation (b) 68,147 63,378 Asset retirement obligations (c) 55,406 24,822 Customer deposits (d) 35,790 14,881 Unamortized investment tax credits (e) 22,379 — Deferred credits (f) 26,555 44,544 Other 55,779 22,790 342,692 275,606 Less current portion (57,586 ) (43,157 ) $ 285,106 $ 232,449 (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 5 to 40 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 2017, $13,626 (2016 - $23,986 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation A number of the Company's regulated utilities 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 $71,873 (2016 - $76,853 ) which at discount rates ranging from 2.2% to 2.5% represents the recorded accrual of $68,147 as of December 31, 2017 (2016 - $63,378 ). Approximately $25,186 is expected to be incurred over the next two years with the balance of cash flows to be incurred over the following 28 years. Changes in the environmental remediation obligation are as follows: 2017 2016 Opening Balance $ 63,378 $ 71,529 Remediation activities (2,026 ) (1,389 ) Accretion 1,447 2,464 Changes in cash flow estimates 2,135 2,088 Revision in assumptions 7,686 (9,101 ) Foreign exchange rate adjustment (4,473 ) (2,213 ) Closing Balance $ 68,147 $ 63,378 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, 2017, the Company has reflected a regulatory asset of $103,761 (2016 - $104,160 ) for the MGP and related sites (note 7(a)). 13. Other long-term liabilities and deferred credits (continued) (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 Polychlorinated Biphenyls "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; (iv) remove certain river water intake structures and equipment; (v) disposal of coal combustion residuals and PCB contaminants and (vi) remove asbestos upon major renovation or demolition of structures and facilities. During the year, APUC assumed asset retirement obligations in connection with the acquisitions of Empire (note 3(a)) and Deerfield SponsorCo (note 8(b)) of $31,717 and $2,816 , respectively, recorded additional asset retirement obligations for renewable generation facilities being constructed of $ 2,604 (2016 - $393 ), changes in estimates of $1,476 (2016 - $1,022 ), accretion expense of $2,551 (2016 - $1,055 ) and settlements of $5,418 (2016 - $nil). As the cost of retirement of utility assets are expected to be recovered through rates, a corresponding regulatory asset is recorded, as well as the on-going liability accretion and asset depreciation expense (note 7(h)). (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) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station. (f) Deferred credits Deferred credits include unresolved contingent consideration related to prior acquisitions which are expected to be paid and deferred tax credits (note 20). |
Convertible Unsecured Subordina
Convertible Unsecured Subordinated Debentures | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Convertible Unsecured Subordinated Debentures | Convertible Unsecured Subordinated Debentures Maturity date March 31, 2026 Interest rate 5.00 % Conversion price per share $ 10.60 Receipt of Initial instalment, net of deferred financing costs $ 357,694 Amortization of deferred financing costs 925 Carrying value at December 31, 2016 358,619 Receipt of Final instalment, net of deferred financing costs 743,881 Amortization of deferred financing costs 1,134 Conversion to common shares $ (1,102,416 ) Carrying value at December 31, 2017 $ 1,218 Face value at December 31, 2017 $ 1,277 On March 1, 2016, the Company completed the sale of $1,150,000 aggregate principal amount of 5.0% convertible debentures. The convertible debentures were sold on an instalment basis at a price of $1,000 principal amount of debenture, of which $333 was received on closing of the debenture offering and the remaining $667 (the “Final Instalment”) was received on February 2, 2017 (“Final Instalment Date”) following satisfaction of conditions precedent to the closing of the acquisition of Empire (note 3(a)). The proceeds received from the initial and final instalments, net of financing costs were $357,694 and $743,881 , respectively. 14. Convertible Unsecured Subordinated Debentures (continued) The convertible debentures mature on March 31, 2026 and bore interest at an annual rate of 5% per $1,000 principal amount of convertible debentures until and including the Final Instalment Date, after which the interest rate is 0% . The interest expense recorded for the year ended December 31, 2017 is $ 9,373 ( 2016 - $ 48,205 ). As the Final Instalment Date occurred prior to the first anniversary of the closing of the debenture offering, holders of the convertible debentures who paid the final instalment by February 2, 2017 received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing the interest that would have accrued from the day following the Final Instalment Date up to and including March 1, 2017. The debentures are convertible into up to 108,490,566 common shares. As at December 31, 2017 , a total of 108,370,081 common shares of the company were issued (Note 15), representing conversion into common shares of 99.9% of the convertible debentures. After the Final Instalment Date, any debentures not converted into common shares 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. |
Shareholders' capital
Shareholders' capital | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Shareholders' capital | Shareholders’ capital (a) Common shares Number of common shares: 2017 2016 Common shares, beginning of year 274,087,018 255,869,419 Public offering (i) and subscription receipts (ii) 43,470,000 12,938,457 Conversion of convertible debentures (note 14) 108,370,081 — Dividend reinvestment plan (iii) 3,905,848 2,322,618 Exercise of share-based awards (c) 1,932,988 2,956,524 Common shares, end of year 431,765,935 274,087,018 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 2019. 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 On November 10, 2017, APUC issued 43,470,000 common shares at $13.25 per share pursuant to a public offering for proceeds of $576,000 before issuance costs of $ 24,342 or $17,895 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(c)). Effective June 30, 2016, Emera converted the subscription receipts for no additional consideration on a one-for-one basis into common shares and received 661,693 additional common shares in lieu of dividends declared during the holding period. 15. Shareholders’ capital (continued) (a) Common shares (continued) (ii) Subscription receipts (continued) 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(i)). Effective June 30, 2016, Emera converted the subscription receipts for no additional consideration on a one-for-one basis into common shares and received 252,011 additional common shares in lieu of dividends declared during the holding period. (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 1,063,572 common shares under the dividend reinvestment plan. (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, 2017 and 2016 : 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 as they are mandatorily redeemable for cash (note 11). 15. Shareholders’ capital (continued) (c) Share-based compensation For the year ended December 31, 2017 , APUC recorded $10,804 (2016 - $5,675 ) in total share-based compensation expense detailed as follows: 2017 2016 Share options $ 3,990 $ 3,006 Directors deferred share units 771 683 Employee share purchase 568 238 Performance share units 5,475 1,748 Total share-based compensation $ 10,804 $ 5,675 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, 2017 , total unrecognized compensation costs related to non-vested options and PSUs were $2,796 and $8,471 , respectively, and are expected to be recognized over a period of 1.61 and 1.84 years, respectively. (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 8% 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. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Board (or the compensation committee of the Board (“Compensation Committee”)) in accordance with the terms of the Company's clawback policy. 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 based on experience to-date. The dividend yield rate was based upon recent historical dividends paid on APUC shares. 15. Shareholders’ capital (continued) (c) Share-based compensation (continued) (i) Share option plan (continued) The following assumptions were used in determining the fair value of share options granted: 2017 2016 Risk-free interest rate 1.4 % 0.9 % Expected volatility 25 % 23 % Expected dividend yield 4.3 % 4.5 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option $ 1.45 $ 1.26 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, 2016 7,164,652 $ 6.92 4.74 $ 28,561 Granted 2,596,025 10.85 8.00 — Exercised (3,715,663 ) 5.25 2.06 20,790 Balance at December 31, 2016 6,045,014 $ 9.64 6.27 $ 10,595 Granted 2,328,343 12.82 8.00 Exercised (1,634,501 ) 7.81 3.76 7,696 Balance at December 31, 2017 6,738,856 $ 11.18 6.32 $ 19,380 Exercisable at December 31, 2017 2,448,689 $ 10.03 5.61 $ 9,473,719 (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, 2017 , a total of 283,523 common shares ( 2016 - 144,264 ) were issued to employees under the ESPP. 15. Shareholders’ capital (continued) (c) Share-based compensation (continued) (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, 2017 , 293,906 ( 2016 - 224,663 ) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by APUC under the DSU Plan shall not exceed 1,000,000 common shares. (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 2.0% to 237% 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. The aggregate number of common shares reserved for issuance from treasury by APUC under the PSU Plan shall not exceed 7,000,000 common shares. Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the balance sheet date. Compensation cost recognized is adjusted to reflect the performance conditions estimated to-date. 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, 2016 564,116 $ 7.59 1.63 $ 6,155 Granted, including dividends 219,315 11.62 2.00 — Exercised (181,875 ) 8.29 — 2,115 Forfeited (22,568 ) 9.64 — — Balance at December 31, 2016 578,988 $ 9.82 1.74 $ 6,595 Granted, including dividends 811,974 13.54 2.00 — Exercised (374,973 ) 8.33 — 4,394 Forfeited (60,961 ) 12.61 — — Balance at December 31, 2017 955,028 $ 12.30 1.84 $ 13,428 Exercisable at December 31, 2017 172,031 $ 9.75 — $ 2,423 |
Accumulated other comprehensive
Accumulated other comprehensive income (loss) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2016 $ 261,357 $ 39,329 $ (72 ) $ (13,877 ) $ 286,737 OCI (loss) before reclassifications (61,029 ) 34,308 213 2,856 (23,652 ) Amounts reclassified — (7,554 ) — (604 ) (8,158 ) Net current period OCI (61,029 ) 26,754 213 2,252 (31,810 ) Balance, December 31, 2016 $ 200,328 $ 66,083 $ 141 $ (11,625 ) $ 254,927 OCI before reclassifications (200,400 ) 8,714 — 838 (190,848 ) Amounts reclassified — (6,805 ) (141 ) — (313 ) (7,259 ) Net current period OCI $ (200,400 ) $ 1,909 $ (141 ) $ 525 $ (198,107 ) Balance, December 31, 2017 $ (72 ) $ 67,992 $ — $ (11,100 ) $ 56,820 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
Dividends Dividends | 12 Months Ended |
Dec. 31, 2017 | |
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: 2017 2016 Dividend Dividend per share Dividend Dividend per share Common shares $ 242,509 $ 0.6084 $ 149,158 $ 0.5452 Series A preferred shares $ 5,400 $ 1.1250 $ 5,400 $ 1.1250 Series D preferred shares $ 5,000 $ 1.2500 $ 5,000 $ 1.2500 |
Related party transactions
Related party transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related party transactions | Related party transactions Emera Inc. An executive at Emera was a member of the Board of APUC until June 8, 2017. The Energy Services Business sold electricity to Maine Public Service Company, and Bangor Hydro, both of which are subsidiaries of Emera. The portion considered related party transactions during 2017 amounts to U.S. $4,397 ( 2016 - U.S. $10,185 ). The Liberty Utilities Group purchased natural gas from Emera for its gas utility customers. The portion considered related party transactions amounts to U.S. $1,006 ( 2016 - U.S. $3,939 ). 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. In 2016, a subsidiary of the Company and Emera Utility Services Inc. entered into a design, engineering, supply and construction agreement for the Tinker transmission upgrade project. The transmission upgrade was placed in service in Q2 2017 with final completion of the contract work in the fourth quarter. The total cost of the contract was $9,500 . The contract followed a market based request for proposal process. On October 14, 2016, APUC paid $680 to Emera as reimbursement for professional services incurred and accrued in 2014 . There was U.S. $1,467 included in accruals in 2017 ( 2016 - U.S. $757 ) related to these transactions at the end of the year. 18. Related party transactions (continued) 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 $5,969 ( 2016 - $3,313 ) during the year. Trafalgar In 2016, the Company received U.S. $10,083 in proceeds from the settlement of the Trafalgar matter, and paid U.S. $2,900 to an entity partially and indirectly owned by Senior Executives as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6,600 was recorded in 2016. Long Sault Hydro Facility 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 remains outstanding. The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions. |
Non-controlling Interests and R
Non-controlling Interests and Redeemable non-controlling Interest | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Abstract] | |
Non-controlling Interests and Redeemable non-controlling Interest | Non-controlling interests and Redeemable non-controlling interest Net loss attributable to non-controlling interests for the years ended December 31 consists of the following: 2017 2016 HLBV and other adjustments attributable to: Non-controlling interest -Class A partnership units $ (52,020 ) $ (35,451 ) Non-controlling interest -redeemable Class A partnership units (13,400 ) (4,952 ) Other net earnings attributable to non-controlling interests 3,172 1,853 Net effect of non-controlling interests $ (62,248 ) $ (38,550 ) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Company's U.S. wind power and solar power generating facilities 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(r). The terms of the arrangement refer to the tax rate in effect when the benefits are delivered. As such, The U.S. federal corporate tax rate of 35% was used to calculate HLBV as at December 31, 2017. The reduced U.S. federal corporate tax rate of 21% and other certain measures discussed in note 20 will be used in the calculation of HLBV beginning in 2018. Non-controlling interest As of December 31, 2017, non-controlling interests of $756,007 ( 2016 - $562,358 ) includes Class A partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $754,932 ( 2016 - $561,308 ) and other non-controlling interests of $1,075 ( 2016 - $1,050 ). Contributions from new Class A partnership investors of U.S. $42,750 was received for the Great Bay Solar Facility in 2017 (note 3(c)); U.S. $9,800 was received for the Bakersfield II Solar Facility on February 28, 2017 (note 3(g)); and, U.S. $166,595 was received for the Deerfield Wind Project on May 10, 2017 (note 8(b)). 19. Non-controlling interests and Redeemable non-controlling interest (continued) Redeemable Non-controlling interest Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The redeemable non-controlling interests in subsidiaries balance is determined using the hypothetical liquidation at book value method subsequent to initial recognition, however, if the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2017. Changes in redeemable non-controlling interest are as follows: 2017 2016 Opening balance $ 29,434 $ 25,751 Net loss attributable to redeemable non-controlling interest (13,400 ) (4,952 ) Contributions from redeemable non-controlling interests (note 3(f)) 40,797 10,171 Dividends declared and distributions to redeemable non-controlling interest (1,454 ) (590 ) Foreign exchange (3,249 ) (946 ) Closing balance $ 52,128 $ 29,434 Contributions from new Class A partnership investors of U.S. $31,212 was received for the Luning Solar Facility on on February 17, 2017 (note 3(f)). |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2017 | |
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% ( 2016 - 26.5% ). The differences are as follows: 2017 2016 Expected income tax expense at Canadian statutory rate $ 59,907 $ 34,317 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (27,671 ) (11,363 ) Non-controlling interests share of income 24,708 13,973 Allowance for equity funds used during construction (1,029 ) (1,100 ) Capital gain rate differential (919 ) (3,612 ) Goodwill divestiture and permanent basis differences associated with Mountain Water condemnation 7,059 — Non-deductible acquisition costs 18,091 1,996 Change in valuation allowance (1,304 ) 2,841 Tax credits (8,162 ) (477 ) Adjustment relating to prior periods (30 ) (711 ) U.S. tax reform 22,390 — Other 2,154 1,272 Income tax expense $ 95,194 $ 37,136 On December 22, 2017, the US Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of legislative changes including a reduction of the US federal corporate income tax rate from 35% to 21% effective January 1, 2018, limitations on the deductibility of interest and 100% expensing of qualified property. The Act provides an exemption to regulated utilities from the limitations on the deductibility of interest and also does not permit regulated utilities to immediately expense 100% of the cost of new investments in qualified property. 20. Income taxes (continued) As a result of the Act being enacted during 2017, the Company is required to revalue its United States deferred income tax assets and liabilities based on the rates they are expected to reverse at in the future, which is generally 21% for U.S. federal tax purposes. The company was able to make reasonable estimates of the impact of the Act and has recorded provisional amounts for the remeasurement of deferred taxes. The Company has recognized a provisional charge to income tax expense of $22,390 in 2017 as a result of the revaluation of its U.S. non-regulated net deferred income tax assets. The Company has also reduced its regulated net deferred income tax liabilities by a provisional amount of $411,409 and recorded an equivalent increase to net regulatory liability since the benefit of lower U.S. taxes is probable of being returned to customers by order of the applicable regulator. The Company is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act. For the years ended December 31, 2017 and 2016 , earnings from continuing operations before income taxes consist of the following: 2017 2016 Canadian operations $ (3,269 ) $ 29 U.S. operations 229,309 129,481 $ 226,040 $ 129,510 Income tax expense (recovery) attributable to income (loss) consists of: Current Deferred Total Year ended December 31, 2017 Canada $ 4,277 $ (18,390 ) $ (14,113 ) United States 5,631 103,676 109,307 $ 9,908 $ 85,286 $ 95,194 Year ended December 31, 2016 Canada $ 7,533 $ (10,501 ) $ (2,968 ) United States 928 39,176 40,104 $ 8,461 $ 28,675 $ 37,136 20. Income taxes (continued) 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, 2017 and 2016 are presented below: 2017 2016 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 412,327 $ 459,436 Pension and OPEB 54,744 57,751 Acquisition-related costs 2,008 3,612 Environmental obligation 18,570 25,683 Reserves and other non-deductible costs 38,453 11,390 Regulatory liabilities 193,942 76,315 Other 20,555 14,374 Total deferred income tax assets 740,599 648,561 Less valuation allowance (15,486 ) (21,656 ) Total deferred tax assets 725,113 626,905 Deferred tax liabilities: Property, plant and equipment (838,110 ) (562,124 ) Intangible assets (8,067 ) (8,035 ) Outside basis in partnership (157,463 ) (187,717 ) Regulatory accounts (143,090 ) (108,506 ) Financial derivatives (1,230 ) (17,649 ) Other — (1,008 ) Total deferred tax liabilities (1,147,960 ) (885,039 ) Net deferred tax liabilities $ (422,847 ) $ (258,134 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 76,972 $ 30,005 Deferred tax liabilities (499,819 ) $ (288,139 ) Net deferred tax liabilities $ (422,847 ) $ (258,134 ) The valuation allowance for deferred tax assets as at December 31, 2017 was $ 15,486 ( 2016 - $21,656 ). 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, 2017 , 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 2020 and onwards $ 1,247,448 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 $188,348 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, 2017 | |
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 15 (a)). 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 convertible debentures (note 14) are convertible into common shares at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. The Final Instalment Date occurred on February 2, 2017, and as such, the shares issuable upon conversion of the convertible debentures are included in diluted earnings per share beginning on that date. 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: 2017 2016 Net earnings attributable to shareholders of APUC $ 193,094 $ 130,924 Series A Preferred shares dividend 5,400 5,400 Series D Preferred shares dividend 5,000 5,000 Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 182,694 $ 120,524 Weighted average number of shares Basic 382,323,434 271,832,430 Effect of dilutive securities 3,662,714 2,244,602 Diluted 385,986,148 274,077,032 The shares potentially issuable as a result of 2,328,343 share options ( 2016 - 1,665,131 ) are excluded from this calculation as they are anti-dilutive. |
Segmented information
Segmented information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segmented information | Segmented information In connection with the acquisition of Empire on January 1, 2017, the Company aligned its management reporting under two primary North American business units consisting of the Liberty Power Group and the Liberty Utilities Group . The two business units are the two segments of the Company. The Liberty Power Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Liberty Utilities Group owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations. 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. The comparative information for 2016 has been reclassified to conform with the composition of the reporting segments presented in the current year. Year ended December 31, 2017 Liberty Power Group Liberty Utilities Group Corporate Total Revenue $ 300,173 $ 1,677,636 $ — $ 1,977,809 Fuel, power and water purchased 25,384 485,016 — 510,400 Net revenue 274,789 1,192,620 — 1,467,409 Operating expenses 86,675 511,983 — 598,658 Administrative expenses 20,777 42,900 789 64,466 Depreciation and amortization 103,038 222,088 1,321 326,447 Gain on foreign exchange — — 373 373 Operating income 64,299 415,649 (2,483 ) 477,465 Interest expense 47,565 126,790 28,276 202,631 Interest, dividend, equity and other income (3,723 ) (5,449 ) (2,817 ) (11,989 ) Other expenses (gain) 2,282 (4,250 ) 62,751 60,783 Earnings (loss) before income taxes $ 18,175 $ 298,558 $ (90,693 ) $ 226,040 Property, plant and equipment $ 2,818,697 $ 5,047,454 $ 43,342 $ 7,909,493 Equity-method investees 37,273 2,784 422 40,479 Total assets 3,103,999 7,299,576 130,060 10,533,635 Capital expenditures 211,328 528,695 — 740,023 22. Segmented information (continued) Year ended December 31, 2016 Liberty Power Group Liberty Utilities Group Corporate Total Revenue $ 265,949 $ 830,069 $ — $ 1,096,018 Fuel and power purchased 21,260 274,055 — 295,315 Net revenue 244,689 556,014 — 800,703 Operating expenses 72,346 260,595 60 333,001 Administrative expenses 19,656 26,272 421 46,349 Depreciation and amortization 80,094 105,448 1,357 186,899 Gain on foreign exchange — — (436 ) (436 ) Operating income 72,593 163,699 (1,402 ) 234,890 Interest expense 21,847 50,671 59,074 131,592 Interest, dividend and other income 32 (5,282 ) (5,323 ) (10,573 ) Other expense (gain) (14,403 ) (11,690 ) 10,454 (15,639 ) Earnings (loss) before income taxes $ 65,117 $ 130,000 $ (65,607 ) $ 129,510 Property, plant and equipment $ 2,455,336 $ 2,390,047 $ 44,563 $ 4,889,946 Equity-method investees 59,021 2,314 3,084 64,419 Total assets 2,771,651 5,388,966 88,843 8,249,460 Capital expenditures 141,420 264,323 — 405,743 The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue. 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: 2017 2016 Revenue Canada $ 95,326 $ 100,403 United States 1,882,483 995,615 $ 1,977,809 $ 1,096,018 Property, plant and equipment Canada $ 568,693 $ 558,271 United States 7,340,800 4,331,675 $ 7,909,493 $ 4,889,946 Intangible assets Canada $ 34,654 $ 36,611 United States 29,454 28,378 $ 64,108 $ 64,989 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, 2017 | |
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. 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. Condemnation Expropriation Proceedings Mountain Water was the subject of a condemnation lawsuit filed by the city of Missoula. On August 2, 2016, the Supreme Court of Montana upheld the District Court’s decision that the city of Missoula could proceed with condemnation of Mountain Water’s assets. The fair market value of the condemned property as of May 6, 2014 was assessed by the Commissioners to be U.S. $88,600 . Upon taking possession of Mountain Water’s assets on June 22, 2017, the city of Missoula paid U.S. $83,863 to Mountain Water, net of closing adjustments and amounts required to be paid by the City directly to various developers in satisfaction of obligations under Funded By Other (FBO) contracts relating to the assets. In connection with Liberty Utilities’ indirect acquisition of Mountain Water in January 2016, Liberty Utilities was permitted and continues to hold-back U.S. $14,400 from the purchase price otherwise payable to Carlyle Infrastructure Partners, L.P. (“Carlyle”) and certain other interest holders. The condemnation of the Mountain Water assets resulted in a gain on long-lived assets of U.S. $4,370 . Liberty Utilities (Apple Valley Ranchos Water) Corp. is the subject of a condemnation lawsuit filed by the town of Apple Valley. A Court will determine the necessity of the taking by Apple Valley and, if established, a jury will determine the fair market value of the assets being condemned. Resolution of the condemnation proceedings is expected to take two to three years. Any taking by government entities would legally require fair compensation to be paid, however, there is no assurance that the value received as a result of the condemnation will be sufficient to recover the Company's net book value of the utility assets taken. (b) Commitments In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2017 . 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) $ 74,025 $ 48,344 $ 49,940 $ 50,214 $ 50,495 $ 254,380 $ 527,398 Gas supply and service agreements (ii) 91,425 66,848 51,809 33,161 28,411 97,489 369,143 Service agreements 47,695 47,211 48,529 48,827 46,548 435,093 673,903 Capital projects 41,054 17,064 65 65 65 16 58,329 Operating leases 9,573 8,974 8,298 8,361 9,718 225,047 269,971 Total $ 263,772 $ 188,441 $ 158,641 $ 140,628 $ 135,237 $ 1,012,025 $ 1,898,744 23. Commitments and contingencies (continued) (b) Commitments (continued) (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, 2017 . 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, 2017 | |
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: 2017 2016 Accounts receivable $ (18,502 ) $ 6,612 Fuel and natural gas in storage (1,970 ) 6,877 Supplies and consumable inventory 1,392 692 Income taxes receivable 1,674 145 Prepaid expenses (897 ) (6,161 ) Accounts payable (23,178 ) 24,524 Accrued liabilities 25,122 (9,454 ) Current income tax liability (3,432 ) (4,552 ) Net regulatory assets and liabilities (54,235 ) (14,979 ) $ (74,026 ) $ 3,704 |
Financial instruments
Financial instruments | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Financial instruments | Financial instruments (a) Fair value of financial instruments 2017 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 41,873 $ 47,912 $ — $ 47,912 $ — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 79,490 79,490 — — 79,490 Energy contracts not designated as a cash flow hedge 137 137 — 137 — Commodity contracts for regulated operations 92 92 — 92 — Transmission congestion rights 7,812 7,812 — 7,812 — Total derivative instruments 87,531 87,531 — 8,041 79,490 Total financial assets $ 129,404 $ 135,443 $ — $ 55,953 $ 79,490 Long-term debt $ 3,863,296 $ 4,093,071 $ 817,895 $ 3,275,176 $ — Convertible debentures 1,218 1,277 1,277 — — Preferred shares, Series C 18,464 18,973 18,973 — Derivative instruments: Energy contracts designated as a cash flow hedge 97 97 — — 97 Energy contracts not designated as a cash flow hedge 39 39 — 39 — Cross-currency swap designated as a net investment hedge 72,023 72,023 — 72,023 — Interest rate swap designated as a hedge 10,613 10,613 — 10,613 — Currency forward contract not designated as a hedge 432 432 — 432 — Commodity contracts for regulated operations 3,286 3,286 — 3,286 — Total derivative instruments 86,490 86,490 — 86,393 97 Total financial liabilities $ 3,969,468 $ 4,199,811 $ 819,172 $ 3,380,542 $ 97 (1) Balance of $553 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value. 25. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2016 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 38,183 $ 47,933 $ — $ 47,933 $ — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 84,554 84,554 — — 84,554 Interest rate swap designated as a hedge 48,093 48,093 — 48,093 — Currency forward contract not designated as a hedge 17,864 17,864 — 17,864 — Commodity contracts for regulatory operations 359 359 — 359 — Total derivative instruments 150,870 150,870 — 66,316 84,554 Total financial assets $ 189,053 $ 198,803 $ — $ 114,249 $ 84,554 Long-term debt $ 3,913,415 $ 3,999,266 $ 517,637 $ 3,481,629 $ — Convertible debentures 358,619 455,975 455,975 — — Preferred shares, Series C 18,460 18,613 — 18,613 — Derivative instruments: Cross-currency swap designated as a net investment hedge 95,404 95,404 — 95,404 — Interest rate swaps designated as a hedge 13,385 13,385 — 13,385 — Commodity contracts for regulated operations 36 36 — 36 — Total derivative instruments 108,825 108,825 — 108,825 — Total financial liabilities $ 4,399,319 $ 4,582,679 $ 973,612 $ 3,609,067 $ — (1) Balance of $314 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value. 25. 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, 2017 and 2016 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, rights 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. Transmission congestion rights positions are fair valued using the most recent monthly auction clearing prices. 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 $22.13 to $121.56 with a weighted average of $33.20 as of December 31, 2017 . 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 25(b)(ii) and 25(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, 2017 and 2016 . (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 and electric 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: 2017 Financial contracts: Swaps 2,518,812 Options 518,866 Forward contracts 12,420,000 15,457,678 25. Financial instruments (continued) (b) Derivative instruments (continued) (i) Commodity derivatives – regulated accounting (continued) 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. Most of the gains or losses on settlement of these contracts are included in the calculation of deferred gas costs (note 7(d)). 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. 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: 2017 2016 Regulatory assets: Swap contracts U.S. $ — U.S. $ — Option contracts U.S. $ — U.S. $ 27 Forward contracts U.S. $ 6,319 U.S. $ — Regulatory liabilities: Swap contracts U.S. $ 287 U.S. $ 175 Option contracts U.S. $ 138 U.S. $ 92 Forward contracts U.S. $ 20,909 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 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) 688,147 December 2023 U.S. $ 40.40 PJM Western HUB 2,926,922 December 2023 U.S. $ 29.26 NI HUB 3,330,876 December 2027 U.S. $ 36.46 ERCOT North HUB On October 25, 2016, the Company entered into forward contracts to purchase U.S. $250,000 10 -year U.S. Treasury bills at an interest rate of 1.8395% and U.S. $250,000 30 -year U.S. Treasury bills at an interest rate of 2.5539% settling on February 13, 2017 in order to reduce the interest rate risk related to the probable issuance on that date of U.S. $500,000 bonds in relation to the acquisition of Empire (note 9(e)). The change in fair value to February 13, 2017 resulted in a gain of U.S. $36,667 . The effective portion of the hedge of U.S. $718 for the year ended December 31, 2017 was recorded in OCI while the ineffective portion was recorded in the consolidated statement of operations. The Company is party to 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 gain of $2,771 for the year ended December 31, 2017 ( 2016 - loss of $3,726 ), which is recorded in OCI. 25. Financial instruments (continued) (b) Derivative instruments (continued) (ii) Cash flow hedges (continued) The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 2017 2016 Effective portion of cash flow hedge, gain $ 8,714 $ 34,355 Amortization of cash flow hedge (30 ) (47 ) Gain reclassified from AOCI (6,775 ) (7,554 ) OCI attributable to shareholders of APUC $ 1,909 $ 26,754 The Company expects $11,612 and $2,643 of unrealized gains currently in AOCI to be reclassified, net of taxes into non-regulated energy sales and interest expense, respectively, within the next twelve months, as the underlying hedged transactions settle. (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 Liberty Power Group ’s revolving credit facility denominated in U.S. dollars in excess of the principal amount on the USD loans receivable from its equity investees as a hedge of the foreign currency exposure of its net investment in the Liberty Power 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 gain of $21,648 for the year ended December 31, 2017 ( 2016 - nil ) was recorded in OCI. Concurrent with its $150,000 , $200,000 and $300,000 debenture offerings in December 2012, January 2014, and January 2017, 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 Liberty Power 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 gain of $23,381 ( 2016 - $ 6,156 ) was recorded in OCI in 2017 . (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. 25. Financial instruments (continued) (b) Derivative instruments (continued) (iv) Other derivatives (continued) 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 25(b)(ii)). 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 was mitigated through the use of currency forward contracts to sell U.S. $38,400 for $47,225 between July 29, 2016 and September 29, 2016. As of December 31, 2017 , these instruments had settled. This currency forward contract was not accounted for as a hedge. The Company was exposed to foreign exchange fluctuations related to the acquisition of the Empire shares denominated in U.S dollar (note 3(a)). This risk was mitigated through the conversion to U.S. dollars of $359,950 from the proceeds received on the initial instalment of convertible unsecured subordinated debentures (note 14) and the use of a currency forward contract to buy an amount of U.S. $567,665 for $744,050 on January 31, 2017. This currency forward contract was not accounted for as a hedge. The settlement of the currency forward contract resulted in a total realized loss of $16,412 for the year ended December 31, 2017 , which is recorded as a loss on foreign exchange in the consolidated statements of operations ( 2016 - gain of $17,684 ). The Company is exposed to foreign exchange fluctuations related to the portion of its dividend declared and payable in U.S. dollars. This risk is mitigated through the use of currency forward contracts. For the year ended December 31, 2017 , a loss on foreign exchange of $432 ( 2016 - $nil) was recorded in the consolidated statements of operations. These currency forward contracts are 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. The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following: 2017 2016 Change in unrealized loss (gain) on derivative financial instruments: Energy derivative contracts $ (52 ) $ (426 ) Currency forward contract 432 (19,810 ) Commodity contracts (3,916 ) — Total change in unrealized gain on derivative financial instruments $ (3,536 ) $ (20,236 ) Realized loss (gain) on derivative financial instruments: Interest rate swaps (193 ) — Energy derivative contracts 730 951 Currency forward contract 16,413 (1,371 ) Total realized loss (gain) on derivative financial instruments $ 16,950 $ (420 ) Loss (gain) on derivative financial instruments not accounted for as hedges 13,414 (20,656 ) Ineffective portion of derivative financial instruments accounted for as hedges 805 1,518 $ 14,219 $ (19,138 ) Amounts recognized in the consolidated statements of operations consist of: Gain on derivative financial instruments (2,626 ) (15,849 ) Loss (gain) on foreign exchange 16,845 (3,289 ) $ 14,219 $ (19,138 ) 25. Financial instruments (continued) (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 Liberty Power Group accounts receivable to be significant as over 90% 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 Liberty Utilities Group which consists of water and wastewater, electric and gas utilities in the United States. In this regard, the credit risk related to the Liberty Utilities Group accounts receivable balances of U.S. $204,380 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 Liberty Utilities Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers. As of December 31, 2017 , the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2017 Canadian $ US $ Cash and cash equivalents and restricted cash $ 26,259 $ 38,491 Accounts receivable 14,468 238,637 Allowance for doubtful accounts — (5,555 ) Notes receivable 37,710 3,318 $ 78,437 $ 274,891 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, 2017 , in addition to cash on hand of $54,550 the Company had $1,145,859 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. 25. Financial instruments (continued) (c) Risk management (continued) Liquidity risk (continued) 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 $ 279,724 $ 570,132 $ 644,969 $ 2,331,327 $ 3,826,152 Convertible Debentures — — — — 1,218 1,218 Advances in aid of construction 1,502 — — 77,134 78,636 Interest on long-term debt 172,659 307,463 250,824 1,275,184 2,006,130 Purchase obligations 501,867 — — — 501,867 Environmental obligation 7,765 18,858 5,373 39,877 71,873 Derivative financial instruments: Cross-currency swap 4,386 8,077 64,726 (5,166 ) 72,023 Interest rate swaps 10,613 — — — 10,613 Currency forward 432 — — — 432 Energy derivative and commodity contracts 2,290 1,035 — 97 3,422 Other obligations 44,969 — — 110,267 155,236 Total obligations $ 1,026,207 $ 905,565 $ 965,892 $ 3,829,938 $ 6,727,602 |
Comparative figures
Comparative figures | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 | |
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(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(r)). |
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. As at September 30 of each year, the Company assesses qualitative and quantitative 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. 1. Significant accounting policies (continued) (d) Accounting for rate regulated operations (continued) 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 or 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”), the Regulator 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. As of December 31, 2016, restricted cash also included cash of U.S. $1,495,774 transfered to a paying agent for purposes of distribution to holders of common shares of The Empire District Electric Company and its subsidiaries (“Empire”) on January 1, 2017 (note 3(a)). Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash 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 | Fuel and natural gas in storage Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, 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(d)) 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 net realizable value of fuel and 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 net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value. |
Property, plant and equipment | Range of useful lives Weighted average useful lives 2017 2016 2017 2016 Generation 3 - 60 3 - 60 33 32 Distribution 5 - 100 5 - 100 40 41 Equipment 5 - 50 5 - 50 13 11 The Company uses 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. In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Liberty Utilities 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, together with the relevant authority, has authorized and committed to the funding of a 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. 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 |
Commonly Owned Facilities | Commonly owned facilities The Company owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60% with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company's share of operating costs are recognized in operating, maintenance and fuel expenditures excluding depreciation expense. |
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. 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. |
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). 1. Significant accounting policies (continued) (m) Variable interest entities (continued) 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 and collectability of both the interest and principal are reasonably assured. 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, other post-employment benefit (“OPEB”), supplemental retirement program (“SERP”) 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, OPEB and SERP 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. |
Share-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 additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital 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 ("LLC") and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units” or "Class A Equity Investors") which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLC and partnership's agreements have liquidation rights and priorities that are different from the underlying percentages ownership interests. In those situations, simply applying the percentage ownership interest to GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 19). The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Class A Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Class A Equity Investors' share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Class A Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments. 1. Significant accounting policies (continued) (r) Non-controlling interests (continued) 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. Qualifying renewable energy projects receive renewable energy credits ("REC") and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The REC and SREC can be traded and the owner of the REC or SREC can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at the time of generation. Any REC's or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses. 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 certain of the Company’s regulated utilities is subject to revenue decoupling mechanisms approved by their respective regulators 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 rates 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 APUC’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 (note 20). Investment tax credits for our rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Other income tax credits are treated as a reduction to 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. 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 on 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. 1. Significant accounting policies (continued) (v) Financial instruments and derivatives (continued) 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, 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 measurement of deferred taxes and 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 issued accounting pronouncements (a) Recently adopted accounting pronouncements The FASB issued ASU 2016-17 Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control. This update amends the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718), to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this update in the first quarter of 2017 had no material impact on the Company's consolidated financial statements. The Company continues to record the stock-based compensation expense adjusted for estimated forfeitures. The FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments, to clarify the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments in this Update is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. The FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships, to clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. 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 adoption of this update in the first quarter of 2017 had no impact on the Company's consolidated financial statements. (b) Recently issued accounting guidance not yet adopted The FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income to allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years . Early application is permitted in any interim period after issuance of the update. The Company is currently assessing the impacts of this update. The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early application is permitted in any interim period after issuance of the update. The Company is currently assessing the impacts of this update. The Company expects to early adopt this update on January 1, 2018. The FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting, to provide clarity and reduce both diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company applies the guidance in this update for modifications subsequent to December 15, 2017. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost, to improve the reporting of defined benefit pension cost and post-retirement benefit cost ("net benefit cost") in the financial statements. This update requires the service cost component to be reported in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update will also only allow the service cost component to be eligible for capitalization when applicable. The Company will adopt this guidance effective January 1, 2018. Following the effective date of this ASU, the Company expects its regulated operations to only capitalize the service costs component and therefore no regulatory to U.S. GAAP reporting differences are anticipated. The Company intends to apply the practical expedient for retrospective application on the statement of operations. The FASB issued ASU 2017-05 Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The update clarifies the scope of the standard as well as provides additional guidance on partial sales of nonfinancial assets. The update is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted however the update must be adopted at the same time as ASU 2014-09. No impact on the consolidated financial statements is expected from the adoption of this update. The FASB issued ASU 2017-04 Business Combinations (Topic 350): Intangibles - Goodwill and Other (Topic 350) Simplifying the Test for Goodwill Impairment. The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The update is intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. The amendments in the Update should be applied prospectively. The Company will follow the pronouncements of this Update after the effective date. The FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash to eliminate current diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. The Company currently present changes in restricted cash as investing activities. The adoption of this standard will change the presentation of restricted cash on the consolidated statement of cash flows. The FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. The new standard requires the recognition of current and deferred income taxes for an intra-entity transfer of an asset other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes on these transactions until the asset has been sold to an outside party. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. No impact on the consolidated financial statements is expected from the adoption of this Update. The FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments in order to eliminate current diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. No impact on the consolidated financial statements is expected from the adoption of this Update. 2. Recently issued accounting pronouncements (continued) (b) Recently issued accounting guidance not yet adopted (continued) The FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. Early adoption for fiscal years and interim periods beginning after December 15, 2018 is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this Update. 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 FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The FASB also voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures. The Company held training sessions with the finance team and is currently in the process of creating an inventory of its lease contracts and analyzing the terms and conditions under the requirements of this new standard. The Company continues to monitor FASB amendments to ASC Topic 842. 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 presentation of unrealized gains/ losses from the Company's available-for-sale investments will change on the consolidated statement of comprehensive income. Certain disclosures with regards to financial liabilities will change based on the updated requirements. The FASB issued a revenue recognition standard codified as ASC 606, Revenue from Contracts with Customers. This 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. The core principal of the accounting guidance is that an entity should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 is expected to require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This new revenue standard is 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 has not elected to early adopt. The Company has completed its impact assessment. At this point, the Company expects the adoption of Topic 606 will have an immaterial impact on the consolidated financial statements and the pattern of revenue recognition. The Company also evaluated the disclosure requirements and determined that the disaggregation of revenue information required by the new standard will not have a significant impact on the Company’s information gathering processes and procedures as the revenue information required by the standard is consistent with historical revenue information gathered by the Company for financial reporting purposes. The Company intends to adopt the new revenue recognition standard using the modified retrospective method. |
Significant accounting polici36
Significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Capitalization of Interest | The AFUDC capitalized that relates to equity funds is recorded as interest, dividend, equity and other income on the consolidated statements of operations. 2017 2016 Interest capitalized on non-regulated property $ 5,558 $ 3,259 AFUDC capitalized on regulated property: Allowance for borrowed funds 1,673 1,167 Allowance for equity funds 3,014 2,774 Total $ 10,245 $ 7,200 |
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 2017 2016 2017 2016 Generation 3 - 60 3 - 60 33 32 Distribution 5 - 100 5 - 100 40 41 Equipment 5 - 50 5 - 50 13 11 |
Business acquisitions and dev37
Business acquisitions and development projects (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Allocation of Assets Acquired and Liabilities Assumed | The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 2,045 Property, plant and equipment 345,254 Notes receivable 1,781 Goodwill 210,463 Regulatory assets 54,548 Other assets 185 Long-term debt (146,727 ) Regulatory liabilities (3,758 ) Pension and OPEB (18,747 ) Deferred income tax liability, net (51,795 ) Other liabilities (40,172 ) Total net assets acquired $ 353,077 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 198 Property, plant and equipment 145,045 Asset retirement obligation (714 ) Non-controlling interest (tax equity) (50,548 ) Total net assets acquired $ 93,981 The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at January 1, 2017 based on their fair values, using the exchange rate on that date of U.S. $1.00 = CAD $1.3427 . Working capital $ 55,441 Property, plant and equipment 2,764,441 Goodwill 1,010,273 Regulatory assets 318,130 Other assets 58,553 Long-term debt (1,218,563 ) Regulatory liabilities (195,489 ) Pension and other post-employment benefits (105,005 ) Deferred income tax liability, net (562,397 ) Other liabilities (102,759 ) Total net assets acquired $ 2,022,625 Cash and cash equivalent $ 2,338 Total net assets acquired, net of cash and cash equivalent $ 2,020,287 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 11,836 Property, plant and equipment 469,222 Asset retirement obligation (4,812 ) Deferred tax liability (4,273 ) Non-controlling interest (tax equity investors) (237,156 ) Net assets $ 234,817 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working Capital $ (14,551 ) Property, plant and equipment 442,086 Construction loan (352,666 ) Asset retirement obligation (2,816 ) Deferred revenue (1,556 ) Deferred tax liability (1,979 ) Net assets acquired $ 68,518 Cash and cash equivalent $ 4,183 Net assets acquired, net of cash and cash equivalent $ 64,335 |
Business Acquisition, Pro Forma Information | The table below presents the consolidated pro forma revenue and net income for the year ended December 31, 2017 and 2016 , assuming the acquisition of Empire had occurred on January 1, 2016. Pro forma net income includes the impact of fair value adjustments incorporated in the preliminary purchase price allocation above and adjustments necessary to reflect the financing costs as if the acquisition had been financed on January 1, 2016. However, non-recurring acquisition-related expenses are excluded from net income. Year Ended December 31 2017 2016 Revenues $ 1,977,809 $ 1,908,340 Net earnings attributable to common shareholders $ 229,976 $ 213,983 |
Property, plant and equipment (
Property, plant and equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment consist of the following: 2017 Cost Accumulated depreciation Net book value Generation $ 2,988,569 $ 494,912 $ 2,493,657 Distribution 5,247,499 483,345 4,764,154 Land 89,935 — 89,935 Equipment and other 143,158 51,026 92,132 Construction in progress Generation 263,418 — 263,418 Distribution 206,197 — 206,197 $ 8,938,776 $ 1,029,283 $ 7,909,493 2016 Cost Accumulated Net book Generation $ 2,613,267 $ 419,227 $ 2,194,040 Distribution 2,638,488 462,454 2,176,034 Land 60,868 — 60,868 Equipment and other 139,961 44,700 95,261 Construction in progress Generation 197,405 — 197,405 Distribution 166,338 — 166,338 $ 5,816,327 $ 926,381 $ 4,889,946 |
Intangible assets and goodwill
Intangible assets and goodwill (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | Intangible assets consist of the following: 2017 Cost Accumulated amortization Net book value Power sales contracts $ 70,929 $ 46,263 $ 24,666 Customer relationships 33,619 11,085 22,534 Interconnection agreements 17,790 882 16,908 $ 122,338 $ 58,230 $ 64,108 6. Intangible assets and goodwill (continued) 2016 Cost Accumulated Net book Power sales contracts $ 72,207 $ 44,641 $ 27,566 Customer relationships 35,979 10,999 24,980 Interconnection agreements 13,000 — 557 12,443 $ 121,186 $ 56,197 $ 64,989 |
Goodwill | Changes in goodwill are as follows: Balance, January 1, 2016 $ 110,493 Business acquisitions 210,463 Foreign exchange (14,315 ) Balance, December 31, 2016 $ 306,641 Business acquisitions (note 3(a)) 1,010,273 Divestiture of operating entity (note 23(a)) (35,107 ) Foreign exchange (85,573 ) Balance, December 31, 2017 $ 1,196,234 |
Regulatory matters (Tables)
Regulatory matters (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | 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. The following regulatory proceedings were recently completed: Utility State Regulatory Proceeding Type Annual Revenue Increase U.S. $'000 Effective Date EnergyNorth Gas System New Hampshire GRC $6,750 Temporary increase effective July 1, 2017 Granite State Electric System New Hampshire General Rate Case ("GRC") $6,105 July 1, 2016 Calpeco Electric System California Post-Test Year Adjustment Mechanism $2,175 January 1, 2018 New England Gas System Massachusetts GRC $8,300 U.S. $7,800 effective March 1, 2016 U.S. $500 effective March 1, 2017 New England Gas System Massachusetts Gas System Enhancement Plan $2,928 May 1, 2017 Midstates Gas System Illinois GRC $2,200 June 7, 2017 Peach State Gas System Georgia GRAM $2,725 March 1, 2016 Bella Vista Water System Rio Rico Water/Sewer System Arizona GRC $1,935 November 1, 2016 CalPeco Electric System California GRC $8,318 January 1, 2016 Various $3,551 2016, 2017 & 2018 7. Regulatory matters (continued) Regulatory assets and liabilities consist of the following: 2017 2016 Regulatory assets Environmental remediation (a) $ 103,761 $ 104,160 Pension and post-employment benefits (b) 132,615 75,527 Debt premium (c) 72,016 25,173 Fuel and commodity costs adjustment (d) 43,311 6,990 Rate adjustment mechanism (e) 44,523 40,602 Clean Energy and other customer programs (f) 25,820 2,106 Deferred construction costs (g) 17,994 — Asset retirement (h) 20,172 2,113 Income taxes (i) 45,847 10,182 Rate case costs (j) 11,660 8,572 Other 33,415 16,539 Total regulatory assets $ 551,134 $ 291,964 Less current regulatory assets (83,508 ) (48,440 ) Non-current regulatory assets $ 467,626 $ 243,524 Regulatory liabilities Income taxes (i) $ 402,868 $ 1,501 Cost of removal (k) 231,064 110,330 Rate-base offset (l) 16,577 20,946 Fuel and commodity costs adjustment (d) 29,535 34,012 Deferred compensation received in relation to lost production (m) 11,789 — Deferred construction costs - fuel related (g) 9,306 — Pension and post-employment benefits (b) 12,648 5,481 Other 11,269 10,464 Total regulatory liabilities $ 725,056 $ 182,734 Less current regulatory liabilities (47,278 ) (47,769 ) Non-current regulatory liabilities $ 677,778 $ 134,965 (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 U.S. $21,626 relates to an 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 service 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. The pension and post-employments benefits liability is related to tracking accounts pertaining primarily to Park Water Company. The amounts recorded in these accounts occur when actual expenses have been less than adopted and refunds are expected to occur in future periods. 7. Regulatory matters (continued) (c) Debt premium Debt premium on acquired debt is recovered as a component of the weighted average cost of debt. (d) Fuel and commodity costs adjustment The revenue from the utilities includes a component which is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas 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 electricity and natural gas 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 25(b)(i)) are recoverable through the commodity costs adjustment. (e) Rate adjustment mechanism Revenue for Calpeco Electric System, Park Water 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 to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. (f) Clean Energy and other customer programs The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. (g) Deferred construction costs Deferred construction costs reflects deferred construction costs and fuel related costs of specific generating facilities of Empire. These amounts are being recovered over the life of the plants. (h) Asset retirement The costs of retirement of assets are expected to be recovered through rates as well as the on-going liability accretion and asset depreciation expense. (i) Income taxes The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates. The Tax Cuts and Jobs Act ("the Act") was enacted on December 22, 2017. Among other provisions, the Act reduces the corporate income tax rate from 35% to 21%. A reduction of regulatory asset and an increase to regulatory liability was recorded for excess deferred taxes probable of being refunded to customers of $411,409 . (j) 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. (k) 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. (l) Rate-base offset The regulators imposed a rate-base offset that will reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of 10-16 years. 7. Regulatory matters (continued) (m) Deferred compensation received in relation to lost production The regulatory liability for deferred compensation received from lost production represents Empire's refund from Southwest Power Administration for lost revenues at one of its generating facilities. These costs are being amortized over the period approved by state regulators. |
Long-term investments (Tables)
Long-term investments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Long Term Investments And Notes Receivable [Abstract] | |
Long-term Investments | Long-term investments consist of the following: 2017 2016 Equity-method investees Red Lily I Wind Facility (a) $ 22,799 $ 23,504 Deerfield Wind Project (b) — 34,727 Amherst Island Wind Project (c) 11,191 558 Other 6,489 5,630 $ 40,479 $ 64,419 Notes receivable Development loans (d) $ 37,710 $ 32,125 Other 4,163 6,058 41,873 38,183 Available-for-sale investment — 169 Other investments 2,115 2,662 Total long-term investments $ 84,467 $ 105,433 (a) Red Lily I Wind Facility Up to April 12, 2016, the Red Lily I Partnership (the “Partnership”) was 100% owned by an independent investor. APUC provided operation and supervision services to the Red Lily I project ("Red Lily I Wind Facility"), a 26.4 MW wind energy facility located in southeastern Saskatchewan. The Company’s investment in the Red Lily I Wind Facility up to that date was in the form of subordinated debt facilities of the Partnership. Effective April 12, 2016, the Company exercised its option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its subordinated loans. The amount by which the carrying value of the Company's investment exceeds the Company's proportionate share of the Partnership's net assets is not material. Due to certain participating rights being held by the minority investor, the decisions which most significantly impact the economic performance of Red Lily I require unanimous consent. As such, APUC is deemed, under U.S. GAAP, to not have control over the Partnership. As APUC exercises significant influence over operating and financial policies of Red Lily I, the Company accounts for the Partnership using the equity method. The Red Lily I Wind Facility contributed equity income of $2,776 (2016 - $ 1,288 ) to the Company's consolidated financial results for the year ended December 31, 2017. 8. Long-term investments (continued) (b) Deerfield Wind Project 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. On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo and obtained control of the facility. Upon acquisition of the initial 50% equity interest of Deerfield SponsorCo, the two members each contributed U.S. $1,000 to the capital of Deerfield SponsorCo. On October 12, 2016, third-party construction loan financing was provided to the Deerfield Wind Project in the amount of U.S. $262,900 and a tax equity agreement was executed. Concurrently, each member contributed another U.S. $19,891 to the capital of Deerfield SponsorCo. Construction was completed during the first quarter of 2017 and sale of power to the utility under the power purchase agreement started on February 21, 2017. The interest capitalized during the year ended December 31, 2017 to the investment while the Deerfield Wind Project was under construction amounts to $nil (2016 - $6,072 ). On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo for U.S. $21,585 and as a result, obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting which requires that the fair value of assets acquired and liabilities assumed in the subsidiary be recognized on the consolidated balance sheet as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(d)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of $nil was recorded on acquisition. On May 10, 2017, tax equity funding of U.S. $166,595 was received. The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working Capital $ (14,551 ) Property, plant and equipment 442,086 Construction loan (352,666 ) Asset retirement obligation (2,816 ) Deferred revenue (1,556 ) Deferred tax liability (1,979 ) Net assets acquired $ 68,518 Cash and cash equivalent $ 4,183 Net assets acquired, net of cash and cash equivalent $ 64,335 (c) Amherst Island Wind Project Windlectric Inc. ("Windlectric") owns a 75 MW construction-stage wind development project (“Amherst Island Wind Project”) in the province of Ontario. On December 20, 2016, Windlectric, a wholly owned subsidiary of the Company at the time, issued fifty percent of its common shares for $50 to a third party and as a result is no longer controlled by APUC. The Company holds an option to acquire the remaining common shares at a fixed price any time prior to January 15, 2019. Windlectric is considered a VIE namely due to the low level of equity at risk at this point. The Company is not considered the primary beneficiary of Windlectric as the two shareholders have joint control and all decisions must be unanimous. As such, on the transaction date, the Company deconsolidated the assets and liabilities of Windlectric and recorded its retained non-controlling investment in equity and notes receivable and payable at fair value. A net gain of nil was recorded on deconsolidation. The Company is accounting for its investment in the joint venture under the equity method. The interest capitalized during the year end ed December 31, 2017 to the investment while the Amherst Island Wind Project is under construction amounts to $1,447 (2016 - $491 ). As at December 31, 2017, the third-party construction debt of the joint venture was $133,765. 8. Long-term investments (continued) (c) Amherst Island Wind Project (continued) As of December 31, 2017, the Company’s maximum exposure to loss of $289,374 is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(d). (d) Development loans The Company entered into committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide 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 equity investees' wind projects. As at December 31, 2017 , the Company has a loan and credit support facility with Windlectric of $37,710 (2016 - $29,723 ). The loan to Windlectric bears interest at an annual rate of 10% on outstanding principal amount and matures on December 31, 2019. The letters of credit are charged an annual fee of 2% on their stated amount. As of December 31, 2017, the following credit support was issued by the Company on behalf of Windlectric: $72,068 letters of credit and guarantees of obligations to the utilities under the PPAs; a guarantee of the obligations under the wind turbine, transmission line, transformer, and other supply agreements; a guarantee of the obligations under the engineering, procurement, and construction management agreements. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at $2,449 using a probability weighted discounted cash flow (level 3). Following acquisition of control of Deerfield SponsorCo (note 8(b)) and Odell SponsorCo LLC (note 8(e)(i)), amounts advanced to the wind project are eliminated on consolidation. The effects of foreign currency exchange rate fluctuations on these advances of a long-term investment nature are recorded in other comprehensive income from the date of acquisition. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures. (e) 2016 transactions i. Odell Wind Facility Up to September 15, 2016, the Company held a 50% equity interest in Odell SponsorCo LLC, which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Facility”) in the state of Minnesota. On September 15, 2016, the Company acquired the remaining 50% interest in Odell SponsorCo LLC for U.S. $26,500 and as a result, obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting, which requires, that the fair value of assets acquired, liabilities assumed and non-controlling interest in the subsidiary, be recognized on the consolidated balance sheets as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(d)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of nil was recorded on acquisition. |
Allocation of Assets Acquired and Liabilities Assumed | The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 2,045 Property, plant and equipment 345,254 Notes receivable 1,781 Goodwill 210,463 Regulatory assets 54,548 Other assets 185 Long-term debt (146,727 ) Regulatory liabilities (3,758 ) Pension and OPEB (18,747 ) Deferred income tax liability, net (51,795 ) Other liabilities (40,172 ) Total net assets acquired $ 353,077 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 198 Property, plant and equipment 145,045 Asset retirement obligation (714 ) Non-controlling interest (tax equity) (50,548 ) Total net assets acquired $ 93,981 The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at January 1, 2017 based on their fair values, using the exchange rate on that date of U.S. $1.00 = CAD $1.3427 . Working capital $ 55,441 Property, plant and equipment 2,764,441 Goodwill 1,010,273 Regulatory assets 318,130 Other assets 58,553 Long-term debt (1,218,563 ) Regulatory liabilities (195,489 ) Pension and other post-employment benefits (105,005 ) Deferred income tax liability, net (562,397 ) Other liabilities (102,759 ) Total net assets acquired $ 2,022,625 Cash and cash equivalent $ 2,338 Total net assets acquired, net of cash and cash equivalent $ 2,020,287 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working capital $ 11,836 Property, plant and equipment 469,222 Asset retirement obligation (4,812 ) Deferred tax liability (4,273 ) Non-controlling interest (tax equity investors) (237,156 ) Net assets $ 234,817 The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date: Working Capital $ (14,551 ) Property, plant and equipment 442,086 Construction loan (352,666 ) Asset retirement obligation (2,816 ) Deferred revenue (1,556 ) Deferred tax liability (1,979 ) Net assets acquired $ 68,518 Cash and cash equivalent $ 4,183 Net assets acquired, net of cash and cash equivalent $ 64,335 |
Long-term debt (Tables)
Long-term debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long Term Debt | Long-term debt consists of the following: Borrowing type Weighted average coupon Maturity Par value 2017 2016 Senior Unsecured Revolving Credit Facilities (a) — 2018-2022 N/A $ 65,017 $ 242,947 Senior Unsecured Bank Credit Facilities (b) — 2018-2019 N/A 169,343 2,140,122 Commercial Paper (c) 2019 N/A 6,994 — Canadian Dollar Borrowings Senior Unsecured Notes (d) 4.61 % 2018-2027 $ 785,669 781,833 487,389 Senior Secured Project Notes 10.27 % 2020-2027 $ 33,568 33,507 35,600 U.S. Dollar Borrowings Senior Unsecured Notes (e) 4.09 % 2020-2047 US$ 1,225,000 1,527,726 700,600 Senior Unsecured Utility Notes (f) 5.98 % 2020-2035 US$ 227,000 309,309 174,206 Senior Secured Utility Bonds (g) 4.95 % 2018-2044 US$ 752,500 969,567 132,551 $ 3,863,296 $ 3,913,415 Less: current portion (15,511 ) (10,075 ) $ 3,847,785 $ 3,903,340 |
Principal Payments | Principal payments due in the next five years and thereafter are as follows: 2018 2019 2020 2021 2022 Thereafter Total $ 279,724 $ 179,107 $ 391,025 $ 152,626 $ 492,343 $ 2,331,327 $ 3,826,152 |
Pension and other post-retire43
Pension and other post-retirement benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [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 2017 2016 2017 2016 Change in projected benefit obligation Projected benefit obligation, beginning of year $ 331,934 $ 269,382 $ 83,097 $ 76,565 Projected benefit obligation assumed from business combination 344,383 63,811 131,263 9,749 Modifications to pension plan — (2,754 ) — (1,235 ) Service cost 17,869 8,435 6,280 2,916 Interest cost 27,346 13,029 8,621 3,525 Actuarial (gain) loss 49,785 6,773 13,321 (2,870 ) Contributions from retirees — — 2,364 547 Gain on curtailment (1,129 ) — (6 ) — Benefits paid (64,605 ) (15,845 ) (8,092 ) (3,230 ) Gain on foreign exchange (48,546 ) (10,897 ) (14,834 ) (2,870 ) Projected benefit obligation, end of year $ 657,037 $ 331,934 $ 222,014 $ 83,097 Change in plan assets Fair value of plan assets, beginning of year 236,369 176,171 29,139 18,149 Plan assets acquired in business combination 247,741 44,258 122,900 10,563 Actual return on plan assets 82,096 17,221 25,612 1,854 Employer contributions 38,833 21,776 2,683 2,317 Benefits paid (64,605 ) (15,845 ) (5,901 ) (2,683 ) Loss on foreign exchange (33,686 ) (7,212 ) (10,737 ) (1,061 ) Fair value of plan assets, end of year $ 506,748 $ 236,369 $ 163,696 $ 29,139 Unfunded status $ (150,289 ) $ (95,565 ) $ (58,318 ) $ (53,958 ) Amounts recognized in the consolidated balance sheets consists of: Non-current assets — — 4,938 — Current liabilities (1,080 ) (436 ) (1,471 ) (1,242 ) Non-current liabilities (149,209 ) (95,129 ) (61,785 ) (52,716 ) Net amount recognized $ (150,289 ) $ (95,565 ) $ (58,318 ) $ (53,958 ) |
Amounts Recognized in Accumulated Other Comprehensive loss | In conjunction with the plan amendments, the assets and projected benefit obligations of amended plans were revalued at the closest month-end date which resulted in an actuarial loss of U.S. $8,204 recorded in OCI. Change in AOCI (before tax) Pension OPEB Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service gains Balance, January 1, 2016 $ 29,461 $ (4,970 ) $ (2,338 ) $ — Additions to AOCI 4,479 (2,754 ) (3,242 ) (1,235 ) Amortization in current period (1,965 ) 765 (80 ) 347 Balance at December 31, 2016 $ 31,975 $ (6,959 ) $ (5,660 ) $ (888 ) Additions to AOCI (3,716 ) — (4,276 ) — Reclassification to regulatory accounts 1,584 — 4,902 — Amortization in current period (1,290 ) 868 321 365 Balance at December 31, 2017 $ 28,553 $ (6,091 ) $ (4,713 ) $ (523 ) Expected amortization in 2018 $ (451 ) $ 781 $ 214 $ 328 |
Weighted Average Assumptions Used to Determine Net Benefit Obligation | Weighted average assumptions used to determine net benefit cost for 2017 and 2016 were as follows: Pension benefits OPEB 2017 2016 2017 2016 Discount rate 4.01 % 4.16 % 4.12 % 4.23 % Expected return on assets 7.01 % 6.41 % 3.88 % 5.50 % Rate of compensation increase 3.00 % 3.00 % N/A N/A Health care cost trend rate Before Age 65 6.25 % 6.50 % Age 65 and after 6.25 % 6.50 % Assumed Ultimate Medical Inflation Rate 4.75 % 4.75 % Year in which Ultimate Rate is reached 2023 2023 Weighted average assumptions used to determine net benefit obligation for 2017 and 2016 were as follows: Pension benefits OPEB 2017 2016 2017 2016 Discount rate 3.43 % 3.95 % 3.60 % 4.04 % Rate of compensation increase 3.00 % 3.00 % N/A N/A Health care cost trend rate Before Age 65 6.25 % 6.25 % Age 65 and after 6.25 % 6.25 % Assumed Ultimate Medical Inflation Rate 4.75 % 4.75 % Year in which Ultimate Rate is reached 2024 2023 |
Effect of One Percent Change in Assumed Health Care Cost Trend Rate (HCCTR) | The effects on total service and interest cost of a one percent change in HCCTR excludes the effects of Empire. 2017 Effect of a 1 percentage point increase in the HCCTR on: Year-end benefit obligation $ 38,047 Total service and interest cost 959 Effect of a 1 percentage point decrease in the HCCTR on: Year-end benefit obligation $ (30,057 ) Total service and interest cost (765 ) |
Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses | Pension benefits OPEB 2017 2016 2017 2016 Service cost $ 17,869 $ 8,435 $ 6,280 $ 2,916 Interest cost 27,346 13,029 8,621 3,525 Expected return on plan assets (32,244 ) (14,854 ) (8,312 ) (1,265 ) Amortization of net actuarial loss (gain) 1,480 1,965 (299 ) 80 Amortization of prior service credits (808 ) (765 ) (339 ) (347 ) Gain on curtailments and settlements (1,394 ) — (6 ) — Amortization of regulatory assets/liability 15,179 4,698 507 1,471 Net benefit cost $ 27,428 $ 12,508 $ 6,452 $ 6,380 |
Target Asset Allocation | The Company’s target asset allocation is as follows: Asset Class Target (%) Range (%) Equity securities 70 % 49% - 79% Debt securities 30 % 21% - 51% Other — % — % The fair values of investments as of December 31, 2017 , by asset category, are as follows: Asset Class Level 1 Percentage Equity securities 505,219 72 % Debt securities 164,281 27 % Other 945 — % |
Expected Benefit Payments | The expected benefit payments over the next ten years are as follows: 2017 2018 2019 2020 2021 2022-2026 Pension plan $ 43,445 $ 39,037 $ 40,132 $ 45,060 $ 45,108 $ 236,821 OPEB 7,353 7,989 8,845 9,425 10,093 58,844 |
Mandatorily redeemable Series44
Mandatorily redeemable Series C preferred shares (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Schedule of Dividend and Redemption Payments | Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are: 2018 $ 1,068 2019 1,282 2020 1,344 2021 1,364 2022 1,390 Thereafter to 2031 15,761 Redemption amount 5,340 27,549 Less amounts representing interest (9,085 ) 18,464 Less current portion (1,068 ) $ 17,396 |
Other assets (Tables)
Other assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | Other assets consist of the following: 2017 2016 Income tax receivable $ 7,485 $ 2,951 Deferred financing costs 4,448 10,198 Other 18,633 6,136 30,566 19,285 Less current portion (8,919 ) (2,951 ) $ 21,647 $ 16,334 |
Other long-term liabilities a46
Other long-term liabilities and deferred credits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Liabilities Disclosure [Abstract] | |
Other Long Term Liabilities | Other long-term liabilities consist of the following: 2017 2016 Advances in aid of construction (a) $ 78,636 $ 105,191 Environmental remediation obligation (b) 68,147 63,378 Asset retirement obligations (c) 55,406 24,822 Customer deposits (d) 35,790 14,881 Unamortized investment tax credits (e) 22,379 — Deferred credits (f) 26,555 44,544 Other 55,779 22,790 342,692 275,606 Less current portion (57,586 ) (43,157 ) $ 285,106 $ 232,449 (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 5 to 40 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 2017, $13,626 (2016 - $23,986 ) was transferred from advances in aid of construction to contributions in aid of construction. (b) Environmental remediation obligation A number of the Company's regulated utilities 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 $71,873 (2016 - $76,853 ) which at discount rates ranging from 2.2% to 2.5% represents the recorded accrual of $68,147 as of December 31, 2017 (2016 - $63,378 ). Approximately $25,186 is expected to be incurred over the next two years with the balance of cash flows to be incurred over the following 28 years. Changes in the environmental remediation obligation are as follows: 2017 2016 Opening Balance $ 63,378 $ 71,529 Remediation activities (2,026 ) (1,389 ) Accretion 1,447 2,464 Changes in cash flow estimates 2,135 2,088 Revision in assumptions 7,686 (9,101 ) Foreign exchange rate adjustment (4,473 ) (2,213 ) Closing Balance $ 68,147 $ 63,378 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, 2017, the Company has reflected a regulatory asset of $103,761 (2016 - $104,160 ) for the MGP and related sites (note 7(a)). 13. Other long-term liabilities and deferred credits (continued) (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 Polychlorinated Biphenyls "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; (iv) remove certain river water intake structures and equipment; (v) disposal of coal combustion residuals and PCB contaminants and (vi) remove asbestos upon major renovation or demolition of structures and facilities. During the year, APUC assumed asset retirement obligations in connection with the acquisitions of Empire (note 3(a)) and Deerfield SponsorCo (note 8(b)) of $31,717 and $2,816 , respectively, recorded additional asset retirement obligations for renewable generation facilities being constructed of $ 2,604 (2016 - $393 ), changes in estimates of $1,476 (2016 - $1,022 ), accretion expense of $2,551 (2016 - $1,055 ) and settlements of $5,418 (2016 - $nil). As the cost of retirement of utility assets are expected to be recovered through rates, a corresponding regulatory asset is recorded, as well as the on-going liability accretion and asset depreciation expense (note 7(h)). (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) Unamortized investment tax credits The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station. (f) Deferred credits Deferred credits include unresolved contingent consideration related to prior acquisitions which are expected to be paid and deferred tax credits (note 20). |
Changes in Environmental Remediation Obligation | Changes in the environmental remediation obligation are as follows: 2017 2016 Opening Balance $ 63,378 $ 71,529 Remediation activities (2,026 ) (1,389 ) Accretion 1,447 2,464 Changes in cash flow estimates 2,135 2,088 Revision in assumptions 7,686 (9,101 ) Foreign exchange rate adjustment (4,473 ) (2,213 ) Closing Balance $ 68,147 $ 63,378 |
Convertible Unsecured Subordi47
Convertible Unsecured Subordinated Debentures (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Convertible Unsecured Subordinated Debentures | Maturity date March 31, 2026 Interest rate 5.00 % Conversion price per share $ 10.60 Receipt of Initial instalment, net of deferred financing costs $ 357,694 Amortization of deferred financing costs 925 Carrying value at December 31, 2016 358,619 Receipt of Final instalment, net of deferred financing costs 743,881 Amortization of deferred financing costs 1,134 Conversion to common shares $ (1,102,416 ) Carrying value at December 31, 2017 $ 1,218 Face value at December 31, 2017 $ 1,277 |
Shareholders' capital (Tables)
Shareholders' capital (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Number of Common Shares | Number of common shares: 2017 2016 Common shares, beginning of year 274,087,018 255,869,419 Public offering (i) and subscription receipts (ii) 43,470,000 12,938,457 Conversion of convertible debentures (note 14) 108,370,081 — Dividend reinvestment plan (iii) 3,905,848 2,322,618 Exercise of share-based awards (c) 1,932,988 2,956,524 Common shares, end of year 431,765,935 274,087,018 |
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, 2017 and 2016 : 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 |
Share-Based Compensation Expense | For the year ended December 31, 2017 , APUC recorded $10,804 (2016 - $5,675 ) in total share-based compensation expense detailed as follows: 2017 2016 Share options $ 3,990 $ 3,006 Directors deferred share units 771 683 Employee share purchase 568 238 Performance share units 5,475 1,748 Total share-based compensation $ 10,804 $ 5,675 |
Fair Value of Share Options Granted | The following assumptions were used in determining the fair value of share options granted: 2017 2016 Risk-free interest rate 1.4 % 0.9 % Expected volatility 25 % 23 % Expected dividend yield 4.3 % 4.5 % Expected life 5.50 years 5.50 years Weighted average grant date fair value per option $ 1.45 $ 1.26 |
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, 2016 7,164,652 $ 6.92 4.74 $ 28,561 Granted 2,596,025 10.85 8.00 — Exercised (3,715,663 ) 5.25 2.06 20,790 Balance at December 31, 2016 6,045,014 $ 9.64 6.27 $ 10,595 Granted 2,328,343 12.82 8.00 Exercised (1,634,501 ) 7.81 3.76 7,696 Balance at December 31, 2017 6,738,856 $ 11.18 6.32 $ 19,380 Exercisable at December 31, 2017 2,448,689 $ 10.03 5.61 $ 9,473,719 |
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, 2016 564,116 $ 7.59 1.63 $ 6,155 Granted, including dividends 219,315 11.62 2.00 — Exercised (181,875 ) 8.29 — 2,115 Forfeited (22,568 ) 9.64 — — Balance at December 31, 2016 578,988 $ 9.82 1.74 $ 6,595 Granted, including dividends 811,974 13.54 2.00 — Exercised (374,973 ) 8.33 — 4,394 Forfeited (60,961 ) 12.61 — — Balance at December 31, 2017 955,028 $ 12.30 1.84 $ 13,428 Exercisable at December 31, 2017 172,031 $ 9.75 — $ 2,423 |
Accumulated other comprehensi49
Accumulated other comprehensive income (loss) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2016 $ 261,357 $ 39,329 $ (72 ) $ (13,877 ) $ 286,737 OCI (loss) before reclassifications (61,029 ) 34,308 213 2,856 (23,652 ) Amounts reclassified — (7,554 ) — (604 ) (8,158 ) Net current period OCI (61,029 ) 26,754 213 2,252 (31,810 ) Balance, December 31, 2016 $ 200,328 $ 66,083 $ 141 $ (11,625 ) $ 254,927 OCI before reclassifications (200,400 ) 8,714 — 838 (190,848 ) Amounts reclassified — (6,805 ) (141 ) — (313 ) (7,259 ) Net current period OCI $ (200,400 ) $ 1,909 $ (141 ) $ 525 $ (198,107 ) Balance, December 31, 2017 $ (72 ) $ 67,992 $ — $ (11,100 ) $ 56,820 |
Dividends (Tables)
Dividends (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Cash Dividends [Abstract] | |
Dividends | Dividends declared in Canadian equivalent dollars during the year were as follows: 2017 2016 Dividend Dividend per share Dividend Dividend per share Common shares $ 242,509 $ 0.6084 $ 149,158 $ 0.5452 Series A preferred shares $ 5,400 $ 1.1250 $ 5,400 $ 1.1250 Series D preferred shares $ 5,000 $ 1.2500 $ 5,000 $ 1.2500 |
Non-controlling Interests and51
Non-controlling Interests and Redeemable non-controlling Interest (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Abstract] | |
Net Loss Attributable to Non-controlling Interests | Net loss attributable to non-controlling interests for the years ended December 31 consists of the following: 2017 2016 HLBV and other adjustments attributable to: Non-controlling interest -Class A partnership units $ (52,020 ) $ (35,451 ) Non-controlling interest -redeemable Class A partnership units (13,400 ) (4,952 ) Other net earnings attributable to non-controlling interests 3,172 1,853 Net effect of non-controlling interests $ (62,248 ) $ (38,550 ) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Company's U.S. wind power and solar power generating facilities 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(r). |
Changes in Redeemable Non-Controlling Interest | Changes in redeemable non-controlling interest are as follows: 2017 2016 Opening balance $ 29,434 $ 25,751 Net loss attributable to redeemable non-controlling interest (13,400 ) (4,952 ) Contributions from redeemable non-controlling interests (note 3(f)) 40,797 10,171 Dividends declared and distributions to redeemable non-controlling interest (1,454 ) (590 ) Foreign exchange (3,249 ) (946 ) Closing balance $ 52,128 $ 29,434 |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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% ( 2016 - 26.5% ). The differences are as follows: 2017 2016 Expected income tax expense at Canadian statutory rate $ 59,907 $ 34,317 Increase (decrease) resulting from: Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (27,671 ) (11,363 ) Non-controlling interests share of income 24,708 13,973 Allowance for equity funds used during construction (1,029 ) (1,100 ) Capital gain rate differential (919 ) (3,612 ) Goodwill divestiture and permanent basis differences associated with Mountain Water condemnation 7,059 — Non-deductible acquisition costs 18,091 1,996 Change in valuation allowance (1,304 ) 2,841 Tax credits (8,162 ) (477 ) Adjustment relating to prior periods (30 ) (711 ) U.S. tax reform 22,390 — Other 2,154 1,272 Income tax expense $ 95,194 $ 37,136 |
Income (Loss) Before Taxes | For the years ended December 31, 2017 and 2016 , earnings from continuing operations before income taxes consist of the following: 2017 2016 Canadian operations $ (3,269 ) $ 29 U.S. operations 229,309 129,481 $ 226,040 $ 129,510 |
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, 2017 Canada $ 4,277 $ (18,390 ) $ (14,113 ) United States 5,631 103,676 109,307 $ 9,908 $ 85,286 $ 95,194 Year ended December 31, 2016 Canada $ 7,533 $ (10,501 ) $ (2,968 ) United States 928 39,176 40,104 $ 8,461 $ 28,675 $ 37,136 |
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, 2017 and 2016 are presented below: 2017 2016 Deferred tax assets: Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 412,327 $ 459,436 Pension and OPEB 54,744 57,751 Acquisition-related costs 2,008 3,612 Environmental obligation 18,570 25,683 Reserves and other non-deductible costs 38,453 11,390 Regulatory liabilities 193,942 76,315 Other 20,555 14,374 Total deferred income tax assets 740,599 648,561 Less valuation allowance (15,486 ) (21,656 ) Total deferred tax assets 725,113 626,905 Deferred tax liabilities: Property, plant and equipment (838,110 ) (562,124 ) Intangible assets (8,067 ) (8,035 ) Outside basis in partnership (157,463 ) (187,717 ) Regulatory accounts (143,090 ) (108,506 ) Financial derivatives (1,230 ) (17,649 ) Other — (1,008 ) Total deferred tax liabilities (1,147,960 ) (885,039 ) Net deferred tax liabilities $ (422,847 ) $ (258,134 ) Consolidated Balance Sheets Classification: Deferred tax assets $ 76,972 $ 30,005 Deferred tax liabilities (499,819 ) $ (288,139 ) Net deferred tax liabilities $ (422,847 ) $ (258,134 ) |
Non Capital Losses Carry Forwards | As of December 31, 2017 , 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 2020 and onwards $ 1,247,448 |
Basic and diluted net earning53
Basic and diluted net earnings per share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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: 2017 2016 Net earnings attributable to shareholders of APUC $ 193,094 $ 130,924 Series A Preferred shares dividend 5,400 5,400 Series D Preferred shares dividend 5,000 5,000 Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted $ 182,694 $ 120,524 Weighted average number of shares Basic 382,323,434 271,832,430 Effect of dilutive securities 3,662,714 2,244,602 Diluted 385,986,148 274,077,032 |
Segmented information (Tables)
Segmented information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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. The comparative information for 2016 has been reclassified to conform with the composition of the reporting segments presented in the current year. Year ended December 31, 2017 Liberty Power Group Liberty Utilities Group Corporate Total Revenue $ 300,173 $ 1,677,636 $ — $ 1,977,809 Fuel, power and water purchased 25,384 485,016 — 510,400 Net revenue 274,789 1,192,620 — 1,467,409 Operating expenses 86,675 511,983 — 598,658 Administrative expenses 20,777 42,900 789 64,466 Depreciation and amortization 103,038 222,088 1,321 326,447 Gain on foreign exchange — — 373 373 Operating income 64,299 415,649 (2,483 ) 477,465 Interest expense 47,565 126,790 28,276 202,631 Interest, dividend, equity and other income (3,723 ) (5,449 ) (2,817 ) (11,989 ) Other expenses (gain) 2,282 (4,250 ) 62,751 60,783 Earnings (loss) before income taxes $ 18,175 $ 298,558 $ (90,693 ) $ 226,040 Property, plant and equipment $ 2,818,697 $ 5,047,454 $ 43,342 $ 7,909,493 Equity-method investees 37,273 2,784 422 40,479 Total assets 3,103,999 7,299,576 130,060 10,533,635 Capital expenditures 211,328 528,695 — 740,023 22. Segmented information (continued) Year ended December 31, 2016 Liberty Power Group Liberty Utilities Group Corporate Total Revenue $ 265,949 $ 830,069 $ — $ 1,096,018 Fuel and power purchased 21,260 274,055 — 295,315 Net revenue 244,689 556,014 — 800,703 Operating expenses 72,346 260,595 60 333,001 Administrative expenses 19,656 26,272 421 46,349 Depreciation and amortization 80,094 105,448 1,357 186,899 Gain on foreign exchange — — (436 ) (436 ) Operating income 72,593 163,699 (1,402 ) 234,890 Interest expense 21,847 50,671 59,074 131,592 Interest, dividend and other income 32 (5,282 ) (5,323 ) (10,573 ) Other expense (gain) (14,403 ) (11,690 ) 10,454 (15,639 ) Earnings (loss) before income taxes $ 65,117 $ 130,000 $ (65,607 ) $ 129,510 Property, plant and equipment $ 2,455,336 $ 2,390,047 $ 44,563 $ 4,889,946 Equity-method investees 59,021 2,314 3,084 64,419 Total assets 2,771,651 5,388,966 88,843 8,249,460 Capital expenditures 141,420 264,323 — 405,743 |
Information on Operations by Geographic Area | Information on operations by geographic area is as follows: 2017 2016 Revenue Canada $ 95,326 $ 100,403 United States 1,882,483 995,615 $ 1,977,809 $ 1,096,018 Property, plant and equipment Canada $ 568,693 $ 558,271 United States 7,340,800 4,331,675 $ 7,909,493 $ 4,889,946 Intangible assets Canada $ 34,654 $ 36,611 United States 29,454 28,378 $ 64,108 $ 64,989 |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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) $ 74,025 $ 48,344 $ 49,940 $ 50,214 $ 50,495 $ 254,380 $ 527,398 Gas supply and service agreements (ii) 91,425 66,848 51,809 33,161 28,411 97,489 369,143 Service agreements 47,695 47,211 48,529 48,827 46,548 435,093 673,903 Capital projects 41,054 17,064 65 65 65 16 58,329 Operating leases 9,573 8,974 8,298 8,361 9,718 225,047 269,971 Total $ 263,772 $ 188,441 $ 158,641 $ 140,628 $ 135,237 $ 1,012,025 $ 1,898,744 23. Commitments and contingencies (continued) (b) Commitments (continued) (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, 2017 . 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, 2017 | |
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: 2017 2016 Accounts receivable $ (18,502 ) $ 6,612 Fuel and natural gas in storage (1,970 ) 6,877 Supplies and consumable inventory 1,392 692 Income taxes receivable 1,674 145 Prepaid expenses (897 ) (6,161 ) Accounts payable (23,178 ) 24,524 Accrued liabilities 25,122 (9,454 ) Current income tax liability (3,432 ) (4,552 ) Net regulatory assets and liabilities (54,235 ) (14,979 ) $ (74,026 ) $ 3,704 |
Financial instruments (Tables)
Financial instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | (a) Fair value of financial instruments 2017 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 41,873 $ 47,912 $ — $ 47,912 $ — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 79,490 79,490 — — 79,490 Energy contracts not designated as a cash flow hedge 137 137 — 137 — Commodity contracts for regulated operations 92 92 — 92 — Transmission congestion rights 7,812 7,812 — 7,812 — Total derivative instruments 87,531 87,531 — 8,041 79,490 Total financial assets $ 129,404 $ 135,443 $ — $ 55,953 $ 79,490 Long-term debt $ 3,863,296 $ 4,093,071 $ 817,895 $ 3,275,176 $ — Convertible debentures 1,218 1,277 1,277 — — Preferred shares, Series C 18,464 18,973 18,973 — Derivative instruments: Energy contracts designated as a cash flow hedge 97 97 — — 97 Energy contracts not designated as a cash flow hedge 39 39 — 39 — Cross-currency swap designated as a net investment hedge 72,023 72,023 — 72,023 — Interest rate swap designated as a hedge 10,613 10,613 — 10,613 — Currency forward contract not designated as a hedge 432 432 — 432 — Commodity contracts for regulated operations 3,286 3,286 — 3,286 — Total derivative instruments 86,490 86,490 — 86,393 97 Total financial liabilities $ 3,969,468 $ 4,199,811 $ 819,172 $ 3,380,542 $ 97 (1) Balance of $553 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value. 25. Financial instruments (continued) (a) Fair value of financial instruments (continued) 2016 Carrying amount Fair Value Level 1 Level 2 Level 3 Notes receivable $ 38,183 $ 47,933 $ — $ 47,933 $ — Derivative instruments (1) : Energy contracts designated as a cash flow hedge 84,554 84,554 — — 84,554 Interest rate swap designated as a hedge 48,093 48,093 — 48,093 — Currency forward contract not designated as a hedge 17,864 17,864 — 17,864 — Commodity contracts for regulatory operations 359 359 — 359 — Total derivative instruments 150,870 150,870 — 66,316 84,554 Total financial assets $ 189,053 $ 198,803 $ — $ 114,249 $ 84,554 Long-term debt $ 3,913,415 $ 3,999,266 $ 517,637 $ 3,481,629 $ — Convertible debentures 358,619 455,975 455,975 — — Preferred shares, Series C 18,460 18,613 — 18,613 — Derivative instruments: Cross-currency swap designated as a net investment hedge 95,404 95,404 — 95,404 — Interest rate swaps designated as a hedge 13,385 13,385 — 13,385 — Commodity contracts for regulated operations 36 36 — 36 — Total derivative instruments 108,825 108,825 — 108,825 — Total financial liabilities $ 4,399,319 $ 4,582,679 $ 973,612 $ 3,609,067 $ — |
Summary of Commodity Volumes Associated with Derivative Contracts | The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts: 2017 Financial contracts: Swaps 2,518,812 Options 518,866 Forward contracts 12,420,000 15,457,678 |
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: 2017 2016 Regulatory assets: Swap contracts U.S. $ — U.S. $ — Option contracts U.S. $ — U.S. $ 27 Forward contracts U.S. $ 6,319 U.S. $ — Regulatory liabilities: Swap contracts U.S. $ 287 U.S. $ 175 Option contracts U.S. $ 138 U.S. $ 92 Forward contracts U.S. $ 20,909 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 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) 688,147 December 2023 U.S. $ 40.40 PJM Western HUB 2,926,922 December 2023 U.S. $ 29.26 NI HUB 3,330,876 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: 2017 2016 Effective portion of cash flow hedge, gain $ 8,714 $ 34,355 Amortization of cash flow hedge (30 ) (47 ) Gain reclassified from AOCI (6,775 ) (7,554 ) OCI attributable to shareholders of APUC $ 1,909 $ 26,754 |
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: 2017 2016 Change in unrealized loss (gain) on derivative financial instruments: Energy derivative contracts $ (52 ) $ (426 ) Currency forward contract 432 (19,810 ) Commodity contracts (3,916 ) — Total change in unrealized gain on derivative financial instruments $ (3,536 ) $ (20,236 ) Realized loss (gain) on derivative financial instruments: Interest rate swaps (193 ) — Energy derivative contracts 730 951 Currency forward contract 16,413 (1,371 ) Total realized loss (gain) on derivative financial instruments $ 16,950 $ (420 ) Loss (gain) on derivative financial instruments not accounted for as hedges 13,414 (20,656 ) Ineffective portion of derivative financial instruments accounted for as hedges 805 1,518 $ 14,219 $ (19,138 ) Amounts recognized in the consolidated statements of operations consist of: Gain on derivative financial instruments (2,626 ) (15,849 ) Loss (gain) on foreign exchange 16,845 (3,289 ) $ 14,219 $ (19,138 ) |
Maximum Credit Risk Exposure for Financial Instruments | As of December 31, 2017 , the Company’s maximum exposure to credit risk for these financial instruments was as follows: December 31, 2017 Canadian $ US $ Cash and cash equivalents and restricted cash $ 26,259 $ 38,491 Accounts receivable 14,468 238,637 Allowance for doubtful accounts — (5,555 ) Notes receivable 37,710 3,318 $ 78,437 $ 274,891 |
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 $ 279,724 $ 570,132 $ 644,969 $ 2,331,327 $ 3,826,152 Convertible Debentures — — — — 1,218 1,218 Advances in aid of construction 1,502 — — 77,134 78,636 Interest on long-term debt 172,659 307,463 250,824 1,275,184 2,006,130 Purchase obligations 501,867 — — — 501,867 Environmental obligation 7,765 18,858 5,373 39,877 71,873 Derivative financial instruments: Cross-currency swap 4,386 8,077 64,726 (5,166 ) 72,023 Interest rate swaps 10,613 — — — 10,613 Currency forward 432 — — — 432 Energy derivative and commodity contracts 2,290 1,035 — 97 3,422 Other obligations 44,969 — — 110,267 155,236 Total obligations $ 1,026,207 $ 905,565 $ 965,892 $ 3,829,938 $ 6,727,602 |
Notes to the Consolidated Fin58
Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements - Narrative (Details) | 12 Months Ended |
Dec. 31, 2017business_unit | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of business units | 2 |
Significant accounting polici59
Significant accounting policies - Additional Information (Detail) CAD in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017CADMWhFacility | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) | |
Significant Accounting Policies [Line Items] | |||
Commonly Owned, Number of Electric Generating Facilities | Facility | 3 | ||
Restricted cash held for common shareholders | $ | $ 1,495,774 | ||
Number of power generating facilities | Facility | 2 | ||
Non-regulated energy sales | CAD 282,558 | CAD 243,149 | |
Interest expense on long-term debt and others | CAD 202,631 | 131,592 | |
Electricity generated from an eligible energy source (megawatt) | MWh | 1 | ||
Long Sault and Saint-Damase Wind Powered Generating Facility | Primary Beneficiary | Power plant | |||
Significant Accounting Policies [Line Items] | |||
Generating assets of Long Sault | CAD 84,550 | 87,189 | |
Long-term debt of Long Sault | 35,914 | 40,398 | |
Long-term debt of Long Sault, with recourse | 3,900 | 6,900 | |
Non-regulated energy sales | 22,743 | 29,132 | |
Operating expenses and amortization | 5,564 | 6,175 | |
Interest expense on long-term debt and others | CAD 3,573 | CAD 4,064 | |
Minimum | |||
Significant Accounting Policies [Line Items] | |||
Ownership interest in commonly owned facilities | 7.52% | ||
Maximum | |||
Significant Accounting Policies [Line Items] | |||
Ownership interest in commonly owned facilities | 60.00% | ||
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 polici60
Significant accounting policies - Capitalization of Interest (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Capitalization [Line Items] | ||
Total | CAD 10,245 | CAD 7,200 |
Non-regulated property | ||
Schedule of Capitalization [Line Items] | ||
Interest capitalized on non-regulated property | 5,558 | 3,259 |
Interest expense | ||
Schedule of Capitalization [Line Items] | ||
AFUDC capitalized on regulated property | 1,673 | 1,167 |
Interest, dividend and other income | ||
Schedule of Capitalization [Line Items] | ||
AFUDC capitalized on regulated property | CAD 3,014 | CAD 2,774 |
Significant accounting polici61
Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
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 | 33 years | 32 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 | 40 years | 41 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 | 13 years | 11 years |
Significant accounting polici62
Significant accounting policies - Commonly Owned Operating Facilities (Details) | 12 Months Ended |
Dec. 31, 2017CAD | |
Accounting Policies [Abstract] | |
Cost of ownership in plant in service | CAD 833,578 |
Accumulated Depreciation | 225,156 |
Expenditures | CAD 99,930 |
Business acquisitions and dev63
Business acquisitions and development projects - Additional Information (Details) $ / shares in Units, CAD in Thousands, $ in Thousands | Sep. 18, 2017USD ($) | Feb. 28, 2017USD ($) | Feb. 17, 2017USD ($) | Feb. 15, 2017MWac | Jan. 01, 2017USD ($)$ / shares | Dec. 31, 2016USD ($) | Dec. 30, 2016USD ($) | Dec. 14, 2016MWac | Nov. 29, 2016USD ($) | Jan. 08, 2016CADwater_utility | Jan. 08, 2016USD ($)water_utility | Aug. 12, 2015MWac | Mar. 31, 2018CAD | Dec. 31, 2016CADMWh$ / kWh | Dec. 31, 2018USD ($) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Mar. 31, 2018$ / shares |
Business Acquisition [Line Items] | |||||||||||||||||||
Additions to property, plant and equipment | CAD | CAD 740,023 | CAD 405,743 | |||||||||||||||||
Property, plant and equipment | CAD | CAD 4,889,946 | 7,909,493 | 4,889,946 | ||||||||||||||||
Intangible assets | CAD | 64,989 | CAD 64,108 | 64,989 | ||||||||||||||||
Empire | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Business combination, purchase price | $ 2,414,000 | ||||||||||||||||||
Business acquisition, cash paid per common share (usd per share) | $ / shares | $ 34 | ||||||||||||||||||
Business combination, liabilities incurred | $ 855,000 | ||||||||||||||||||
Intangible asset, useful life | 39 years | 39 years | |||||||||||||||||
Park Water Company | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Business combination, purchase price | CAD 353,077 | $ 249,540 | |||||||||||||||||
Business combination, liabilities incurred | $ 91,750 | ||||||||||||||||||
Number of regulated water utilities | water_utility | 3 | 3 | |||||||||||||||||
Revenue | CAD | CAD 91,817 | 96,695 | |||||||||||||||||
Pre-tax net earnings | CAD | CAD 17,620 | CAD 25,374 | |||||||||||||||||
Great Bay Solar Project | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Solar power capacity (megawatt ac) | MWac | 75 | ||||||||||||||||||
Great Bay Solar Facility | Partnership | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Partnership agreement, funded amount | $ 42,750 | ||||||||||||||||||
Great Bay Solar Facility | Partnership | Tax Investor | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Partnership agreement, funded amount | $ 59 | ||||||||||||||||||
Luning Solar Facility | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Solar power capacity (megawatt ac) | MWac | 50 | ||||||||||||||||||
Luning Solar Facility | Partnership | Tax Investor | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Partnership agreement, funded amount | $ 31,212 | $ 7,826 | |||||||||||||||||
Bakersfield Solar Project | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Solar power capacity (megawatt ac) | MWac | 20 | ||||||||||||||||||
Bakersfield Solar Project II | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Solar power capacity (megawatt ac) | MWac | 10 | ||||||||||||||||||
Bakersfield Solar Project II | Tax Investor | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Partnership agreement, funded amount | $ 9,800 | $ 2,454 | |||||||||||||||||
Wind Turbine Components | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Additions to property, plant and equipment | CAD | CAD 75,000 | ||||||||||||||||||
Renewable energy production tax credit (usd per kwh) | $ / kWh | 0.023 | ||||||||||||||||||
Acquisition Facility | Line of Credit | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Proceed from long-term lines of credit | $ 1,336,440 | ||||||||||||||||||
Minimum | Wind Turbine Components | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Wind power capacity (megawatt) | MWh | 500 | ||||||||||||||||||
Maximum | Wind Turbine Components | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Wind power capacity (megawatt) | MWh | 700 | ||||||||||||||||||
Weighted Average | Park Water Company | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Estimated useful lives | 40 years | 40 years | |||||||||||||||||
Bridge Loan | Acquisition Facility | Line of Credit | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Proceed from long-term lines of credit | $ 1,336,440 | $ 1,336,440 | |||||||||||||||||
Scenario, Forecast [Member] | Perris Water Distribution System | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Business combination, purchase price | $ 12 | ||||||||||||||||||
Scenario, Forecast [Member] | St. Lawrence Gas Company, Inc. | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Business combination, purchase price | $ 70 | ||||||||||||||||||
Atlantica Yield | Scenario, Forecast [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Equity interest | 25.00% | ||||||||||||||||||
Total purchase price | CAD | CAD 608 | ||||||||||||||||||
Equity Method Investment, Share Price | $ / shares | $ 24.25 | ||||||||||||||||||
Business Acquisition, Share Price, Contingent Payment | $ / shares | $ 0.60 |
Business acquisitions and dev64
Business acquisitions and development projects - Acquisition of Empire (Details) - CAD CAD in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition [Line Items] | |||
Goodwill (note 6) | CAD 1,196,234 | CAD 306,641 | CAD 110,493 |
Business Acquisition, Pro Forma Information [Abstract] | |||
Revenues | 1,977,809 | 1,908,340 | |
Net earnings attributable to common shareholders | 229,976 | CAD 213,983 | |
Empire | |||
Business Acquisition [Line Items] | |||
Working capital | 55,441 | ||
Property, plant and equipment | 2,764,441 | ||
Goodwill (note 6) | 1,010,273 | ||
Regulatory assets | 318,130 | ||
Other assets | 58,553 | ||
Long-term debt | (1,218,563) | ||
Regulatory liabilities | (195,489) | ||
Pension and OPEB | (105,005) | ||
Deferred income tax liability, net | (562,397) | ||
Other liabilities | (102,759) | ||
Total net assets acquired | 2,022,625 | ||
Cash and cash equivalent | 2,338 | ||
Net assets acquired, net of cash and cash equivalent | CAD 2,020,287 |
Business acquisitions and dev65
Business acquisitions and development projects - Acquisition of Luning Solar Facility (Details) CAD in Thousands, $ in Thousands | Feb. 17, 2017USD ($) | Feb. 15, 2017USD ($)MWac | Dec. 31, 2016USD ($) | Feb. 15, 2017CAD |
Luning Solar Facility | ||||
Business Acquisition [Line Items] | ||||
Business combination, purchase price | $ | $ 111 | |||
Working capital | CAD 198 | |||
Property, plant and equipment | 145,045 | |||
Asset retirement obligation | (714) | |||
Non-controlling interest (tax equity) | (50,548) | |||
Total net assets acquired | CAD 93,981 | |||
Luning Solar Facility | ||||
Business Acquisition [Line Items] | ||||
Solar power capacity (megawatt ac) | MWac | 50 | |||
Partnership | Tax Investor | Luning Solar Facility | ||||
Business Acquisition [Line Items] | ||||
Partnership agreement, funded amount | $ | $ 31,212 | $ 7,826 |
Business acquisitions and dev66
Business acquisitions and development projects - Acquisition of Park Water System (Details) CAD in Thousands, $ in Thousands | Jan. 08, 2016CADwater_utility | Jan. 08, 2016USD ($)water_utility | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2015CAD |
Business Acquisition [Line Items] | |||||
Goodwill (note 6) | CAD 1,196,234 | CAD 306,641 | CAD 110,493 | ||
Park Water Company | |||||
Business Acquisition [Line Items] | |||||
Working capital | CAD 2,045 | ||||
Property, plant and equipment | 345,254 | ||||
Notes receivable | 1,781 | ||||
Goodwill (note 6) | 210,463 | ||||
Regulatory assets | 54,548 | ||||
Other assets | 185 | ||||
Long-term debt | (146,727) | ||||
Regulatory liabilities | (3,758) | ||||
Pension and OPEB | (18,747) | ||||
Deferred income tax liability, net | (51,795) | ||||
Other liabilities | (40,172) | ||||
Total net assets acquired | CAD 353,077 | ||||
Number of regulated water utilities | water_utility | 3 | 3 | |||
Business combination, purchase price | CAD 353,077 | $ 249,540 | |||
Business combination, liabilities incurred | $ | $ 91,750 | ||||
Revenue | 91,817 | 96,695 | |||
Pre-tax net earnings | CAD 17,620 | CAD 25,374 | |||
Weighted Average | Park Water Company | |||||
Business Acquisition [Line Items] | |||||
Estimated useful lives | 40 years | 40 years |
Accounts receivable - Additiona
Accounts receivable - Additional Information (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for doubtful accounts receivable | CAD 6,968 | CAD 7,064 |
Unbilled revenue | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable balances | CAD 98,214 | CAD 57,822 |
Property, plant and equipment -
Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | ||
Cost | CAD 8,938,776 | CAD 5,816,327 |
Accumulated depreciation | 1,029,283 | 926,381 |
Net book value | 7,909,493 | 4,889,946 |
Land | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 89,935 | 60,868 |
Accumulated depreciation | 0 | 0 |
Net book value | 89,935 | 60,868 |
Equipment and other | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 143,158 | 139,961 |
Accumulated depreciation | 51,026 | 44,700 |
Net book value | 92,132 | 95,261 |
Generation | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 2,988,569 | 2,613,267 |
Accumulated depreciation | 494,912 | 419,227 |
Net book value | 2,493,657 | 2,194,040 |
Generation | Construction in progress | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 263,418 | 197,405 |
Accumulated depreciation | 0 | 0 |
Net book value | 263,418 | 197,405 |
Liberty Utilities Group | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 5,247,499 | 2,638,488 |
Accumulated depreciation | 483,345 | 462,454 |
Net book value | 4,764,154 | 2,176,034 |
Liberty Utilities Group | Construction in progress | ||
Property, Plant and Equipment [Line Items] | ||
Cost | 206,197 | 166,338 |
Accumulated depreciation | 0 | 0 |
Net book value | CAD 206,197 | CAD 166,338 |
Property, plant and equipment69
Property, plant and equipment - Additional Information (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant, and Equipment Disclosure [Line Items] | ||
Contribution received | CAD 16,044 | CAD 49,794 |
Water & wastewater | ||
Property, Plant, and Equipment Disclosure [Line Items] | ||
Expansion costs | 1,000 | |
St Damase Wind Facility | ||
Property, Plant, and Equipment Disclosure [Line Items] | ||
Contribution received | 14 | |
Generation | ||
Property, Plant, and Equipment Disclosure [Line Items] | ||
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE | 142,789 | 142,246 |
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation | 43,792 | 39,958 |
Depreciation expense | 2,117 | CAD 2,117 |
Distribution | ||
Property, Plant, and Equipment Disclosure [Line Items] | ||
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE | 2,234,243 | |
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation | CAD 587,202 |
Intangible assets and goodwil70
Intangible assets and goodwill - Schedule of Intangible Assets (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Finite-Lived Intangible Assets [Line Items] | ||
Cost | CAD 122,338 | CAD 121,186 |
Accumulated amortization | 58,230 | 56,197 |
Net book value | 64,108 | 64,989 |
Power sales contracts | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 70,929 | 72,207 |
Accumulated amortization | 46,263 | 44,641 |
Net book value | 24,666 | 27,566 |
Customer relationships | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 33,619 | 35,979 |
Accumulated amortization | 11,085 | 10,999 |
Net book value | 22,534 | 24,980 |
Interconnection agreements | ||
Finite-Lived Intangible Assets [Line Items] | ||
Cost | 17,790 | 13,000 |
Accumulated amortization | 882 | 557 |
Net book value | CAD 16,908 | CAD 12,443 |
Intangible assets and goodwil71
Intangible assets and goodwill - Additional Information (Detail) CAD in Thousands | Dec. 31, 2017CAD |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
Estimated amortization expense for intangibles in year 1 | CAD 3,540 |
Estimated amortization expense for intangibles in year 2 | 3,390 |
Estimated amortization expense for intangibles in year 3 | 3,380 |
Estimated amortization expense for intangibles in year 4 | 3,040 |
Estimated amortization expense for intangibles in year 5 | CAD 2,720 |
Intangible assets and goodwil72
Intangible assets and goodwill - Schedule of Goodwill (Details) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Goodwill [Roll Forward] | ||
Goodwill beginning of the period | CAD 306,641 | CAD 110,493 |
Business acquisitions | 1,010,273 | 210,463 |
Divestiture of operating entity (note 23(a)) | (35,107) | |
Foreign exchange | (85,573) | (14,315) |
Goodwill end of the period | CAD 1,196,234 | CAD 306,641 |
Regulatory matters - Approved A
Regulatory matters - Approved Annual Revenue Increases (Details) CAD in Thousands, $ in Thousands | Apr. 12, 2017USD ($) | Dec. 08, 2016USD ($) | Nov. 21, 2016USD ($) | Jun. 30, 2016USD ($) | Feb. 18, 2016USD ($) | Feb. 10, 2016USD ($) | May 31, 2017CAD | Apr. 30, 2017USD ($) |
New Hampshire Public Utilities Commission | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved revenue increase | $ 6,750 | $ 6,105 | ||||||
Massachusetts Department of Public Utilities | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved rate increase | $ 2,928 | |||||||
Illinois Commerce Commission | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved rate increase | CAD | CAD 2,200 | |||||||
Arizona Corporate Commission | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved revenue increase | $ 1,935 | $ 2,725 | ||||||
California Public Utilities Commission | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved revenue increase | $ 8,318 | 2,175 | ||||||
Various | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved revenue increase | $ 3,551 | |||||||
Annual Revenue Increase Approval, March 2016 | Massachusetts Department of Public Utilities | ||||||||
Regulatory Liabilities [Line Items] | ||||||||
Approved revenue increase | $ 8,300 |
Regulatory matters - Regulatory
Regulatory matters - Regulatory Assets and Liabilities (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 551,134 | CAD 291,964 |
Less current regulatory assets | (83,508) | (48,440) |
Non-current regulatory assets | 467,626 | 243,524 |
Total regulatory liabilities | 725,056 | 182,734 |
Less current regulatory liabilities | (47,278) | (47,769) |
Non-current regulatory liabilities | 677,778 | 134,965 |
Reduction of regulatory asset | 411,409 | |
Increase of regulatory liability | 411,409 | |
Taxes | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 402,868 | 1,501 |
Cost of removal | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 231,064 | 110,330 |
Rate-base offset | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 16,577 | 20,946 |
Fuel and commodity costs adjustment | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 29,535 | 34,012 |
Deferred compensation received in relation to lost production | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 11,789 | 0 |
Deferred construction costs - fuel related | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 9,306 | 0 |
Pension and post-employment benefits | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | 12,648 | 5,481 |
Other | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory liabilities | CAD 11,269 | 10,464 |
Rate adjustment | ||
Regulatory Assets And Liabilities [Line Items] | ||
Collection period for services rendered | 24 months | |
Environmental remediation | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 103,761 | 104,160 |
Regulatory assets recovery period | 7 years | |
Pension and post-employment benefits | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 132,615 | 75,527 |
Portion related to current acquisition | CAD 21,626 | |
Regulatory asset approved not yet being recovered, average recovery term | 10 years | |
Debt premium | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 72,016 | 25,173 |
Fuel and commodity costs adjustment | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 43,311 | 6,990 |
Rate adjustment | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 44,523 | 40,602 |
Clean Energy and other customer programs | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 25,820 | 2,106 |
Deferred construction costs - fuel related | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 17,994 | 0 |
Asset retirement | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 20,172 | 2,113 |
Taxes | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 45,847 | 10,182 |
Rate case costs | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | 11,660 | 8,572 |
Other | ||
Regulatory Assets And Liabilities [Line Items] | ||
Total regulatory assets | CAD 33,415 | CAD 16,539 |
Minimum | Rate-base offset | ||
Regulatory Assets And Liabilities [Line Items] | ||
Amortization period for regulatory liability | 10 years | |
Maximum | Rate-base offset | ||
Regulatory Assets And Liabilities [Line Items] | ||
Amortization period for regulatory liability | 16 years |
Long-term investments - Schedul
Long-term investments - Schedule of Long-Term Investments (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Equity-method investees | CAD 40,479 | CAD 64,419 |
Available-for-sale investment | 0 | 169 |
Other investments | 2,115 | 2,662 |
Total long-term investments | 84,467 | 105,433 |
Notes Receivable | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Notes receivable | 41,873 | 38,183 |
Notes Receivable | Development loans | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Notes receivable | 37,710 | 32,125 |
Notes Receivable | Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Notes receivable | 4,163 | 6,058 |
Red Lily I Wind Facility | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Equity-method investees | 22,799 | 23,504 |
Deerfield Wind Project | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Equity-method investees | 0 | 34,727 |
Interest in Amherst Wind Project | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Equity-method investees | 11,191 | 558 |
Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Equity-method investees | 6,489 | 5,630 |
Variable Interest Entity, Not Primary Beneficiary | Windlectric | Notes Receivable | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Notes receivable | CAD 37,710 | CAD 29,723 |
Long-term investments - Additio
Long-term investments - Additional Information (Detail) CAD / shares in Units, $ in Thousands | Mar. 14, 2017CAD | Dec. 20, 2016CADshareholderCAD / sharesMW | Oct. 12, 2016USD ($) | Sep. 15, 2016CADpartyMW | Sep. 15, 2016USD ($)partyMW | Apr. 12, 2016 | Oct. 19, 2015USD ($)memberMW | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017CADMW | Dec. 31, 2016CAD | May 10, 2017CAD |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Red Lily I Project, wind energy facility, capacity (megawatt) | MW | 26.4 | |||||||||||
Equity-method investees | CAD 40,479,000 | CAD 64,419,000 | CAD 40,479,000 | CAD 64,419,000 | ||||||||
Proceeds from issuance of debt | 1,838,035,000 | 2,399,009,000 | ||||||||||
Number of parties included in development loan | party | 2 | 2 | ||||||||||
Notes Receivable | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Notes receivable | 41,873,000 | 38,183,000 | 41,873,000 | 38,183,000 | ||||||||
Development loans | Notes Receivable | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Notes receivable | 37,710,000 | 32,125,000 | CAD 37,710,000 | 32,125,000 | ||||||||
Interest in Red LIly I Partnership | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Equity interest | 100.00% | |||||||||||
75% Interest in Red Lily I Partnership | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Income (loss) from equity method investments | 2,776,000 | 1,288,000 | ||||||||||
75% Interest in Red Lily I Partnership | Maximum | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Option to subscribe equity interest in partnership, percentage | 75.00% | |||||||||||
50% interest in Odell and Deerfield Wind Projects | Development loans | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Letter of credit fee percent | 2.00% | |||||||||||
50% Interest in Deerfield Wind Project | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Equity-method investees | 0 | 34,727,000 | CAD 0 | 34,727,000 | ||||||||
Equity interest | 50.00% | |||||||||||
Project power capacity (megawatt) | MW | 150 | |||||||||||
Number of members | member | 2 | |||||||||||
Contributions of capital | $ | $ 262,900 | |||||||||||
Interest capitalized on non-regulated property | 6,072,000 | |||||||||||
50% Interest in Deerfield Wind Project | Deerfield SponsorCo | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Contributions of capital | $ | $ 19,891 | $ 1,000 | ||||||||||
50% interest in Odell Wind Project | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Equity interest | 50.00% | 50.00% | ||||||||||
Project power capacity (megawatt) | MW | 200 | 200 | ||||||||||
Interest in Amherst Wind Project | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Equity-method investees | 11,191,000 | 558,000 | 11,191,000 | 558,000 | ||||||||
Interest capitalized on non-regulated property | 1,447,000 | 491,000 | ||||||||||
Deerfield SponsorCo | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Equity interest | 50.00% | 50.00% | ||||||||||
Business combination, purchase price | CAD 21,585,000 | |||||||||||
Tax equity funding received | CAD 166,595,000 | |||||||||||
Interest in natural gas pipeline development | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Equity method investment, realized gain (loss) on disposal | 6,367,000 | |||||||||||
Amherst and Deerfield Wind Projects | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Accrued interest revenue | 0 | 0 | ||||||||||
Odell SponsorCo | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Business acquisition, percentage of voting interest acquired | 50.00% | 50.00% | ||||||||||
Payments to acquired businesses | $ | $ 26,500 | |||||||||||
Business combination, step acquisition, equity interest in acquiree, remeasurement gain | CAD 0 | |||||||||||
Variable Interest Entity, Not Primary Beneficiary | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount | 289,374,000 | 289,374,000 | ||||||||||
Variable interest entity, number of shareholders with joint control | shareholder | 2 | |||||||||||
Net gain on acquisition | CAD 0 | |||||||||||
Variable Interest Entity, Not Primary Beneficiary | Windlectric | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Letters of Credit and Guarantees of Obligations | 72,068,000 | 72,068,000 | ||||||||||
Guarantee Obligation Liability, Noncurrent | 2,449,000 | 2,449,000 | ||||||||||
Variable Interest Entity, Not Primary Beneficiary | Windlectric | Notes Receivable | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Notes receivable | CAD 37,710,000 | CAD 29,723,000 | CAD 37,710,000 | CAD 29,723,000 | ||||||||
Windlectric | ||||||||||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||||||||||
Project power capacity (megawatt) | MW | 75 | |||||||||||
Sale of stock, percentage of commons shares sold | 50.00% | |||||||||||
Sale of stock, price per share (CAD per share) | CAD / shares | CAD 50 |
Long-term investments - Prelimi
Long-term investments - Preliminary Allocation of the Assets Acquired and Liabilities Assumed (Detail) - CAD | Dec. 31, 2017 | Sep. 15, 2016 |
Odell SponsorCo | ||
Business Acquisition [Line Items] | ||
Working capital | CAD 11,836,000 | |
Property, plant and equipment | 469,222,000 | |
Asset retirement obligation | (4,812,000) | |
Deferred tax liability | (4,273,000) | |
Non-controlling interest (tax equity investors) | CAD 237,156,000 | |
Net assets acquired | CAD 234,817,000 | |
Deerfield SponsorCo | ||
Business Acquisition [Line Items] | ||
Working capital | (14,551,000) | |
Property, plant and equipment | 442,086,000 | |
Construction loan | (352,666,000) | |
Asset retirement obligation | (2,816,000) | |
Deferred revenue | (1,556,000) | |
Deferred tax liability | (1,979,000) | |
Net assets acquired | 68,518,000 | |
Cash and cash equivalent | 4,183,000 | |
Net assets acquired, net of cash and cash equivalent | CAD 64,335,000 |
Long-term debt - Schedule of Lo
Long-term debt - Schedule of Long-term Debt (Detail) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD |
Debt Instrument [Line Items] | |||
Less: current portion | CAD (15,511,000) | CAD (10,075,000) | |
Long-term debt, excluding current portion | 3,847,785,000 | 3,903,340,000 | |
Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Long-term debt | 3,863,296,000 | 3,913,415,000 | |
Less: current portion | (15,511,000) | (10,075,000) | |
Long-term debt, excluding current portion | CAD 3,847,785,000 | 3,903,340,000 | |
Senior Unsecured Notes | Canadian Dollar Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Weighted average coupon | 4.61% | 4.61% | |
Par value | CAD 785,669,000 | ||
Long-term debt | CAD 781,833,000 | 487,389,000 | |
Senior Unsecured Notes | Canadian Dollar Senior Secured Project Notes | |||
Debt Instrument [Line Items] | |||
Weighted average coupon | 10.27% | 10.27% | |
Par value | CAD 33,568,000 | ||
Long-term debt | CAD 33,507,000 | 35,600,000 | |
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Weighted average coupon | 4.09% | 4.09% | |
Par value | $ | $ 1,225,000,000 | ||
Long-term debt | CAD 1,527,726,000 | 700,600,000 | |
Senior Unsecured Notes | U.S. Dollar Senior Unsecured Utility Notes | |||
Debt Instrument [Line Items] | |||
Weighted average coupon | 5.98% | 5.98% | |
Par value | $ | $ 227,000,000 | ||
Long-term debt | CAD 309,309,000 | 174,206,000 | |
Senior Unsecured Notes | U.S Dollar Senior Secured Utility Bonds | |||
Debt Instrument [Line Items] | |||
Weighted average coupon | 4.95% | 4.95% | |
Par value | $ | $ 752,500,000 | ||
Long-term debt | CAD 969,567,000 | 132,551,000 | |
Revolving Credit Facility | Senior Unsecured Notes | |||
Debt Instrument [Line Items] | |||
Weighted average coupon | 0.00% | 0.00% | |
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Revolving Credit Facilities (a) | |||
Debt Instrument [Line Items] | |||
Long-term debt | CAD 65,017,000 | 242,947,000 | |
Revolving Credit Facility | Senior Unsecured Notes | Senior Unsecured Bank Credit Facilities (b) | |||
Debt Instrument [Line Items] | |||
Long-term debt | 169,343,000 | 2,140,122,000 | |
Revolving Credit Facility | Senior Unsecured Notes | Commercial Paper | |||
Debt Instrument [Line Items] | |||
Long-term debt | CAD 6,994,000 | CAD 0 |
- Narrative (Detail)
- Narrative (Detail) | Mar. 24, 2017CADTranche | Feb. 08, 2017USD ($) | Jan. 01, 2017USD ($)Tranche | Dec. 30, 2016USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Feb. 23, 2018USD ($) | Feb. 15, 2018CAD | Dec. 31, 2017USD ($) | Dec. 21, 2017CAD | Oct. 06, 2017CAD | Oct. 06, 2017USD ($) | Oct. 05, 2017USD ($) | Sep. 30, 2017CAD | Sep. 20, 2017CAD | Jun. 30, 2017USD ($) | Mar. 14, 2017USD ($) | Jan. 17, 2017CAD | Dec. 31, 2016USD ($) | Oct. 25, 2016USD ($) | Jan. 08, 2016CAD | Jan. 08, 2016USD ($) | Jan. 04, 2016USD ($)bank |
Debt Instrument [Line Items] | |||||||||||||||||||||||
Short-term Debt | CAD | CAD 264,214,000 | ||||||||||||||||||||||
Maturity date | 2.33% | ||||||||||||||||||||||
Notes payable | CAD | CAD 669,000 | ||||||||||||||||||||||
Repayment of long-term debt | CAD | 3,131,717,000 | CAD 68,423,000 | |||||||||||||||||||||
Interest on long term debt | CAD | 41,479,000 | 27,225,000 | |||||||||||||||||||||
Interest expense during the year on long-term liabilities | CAD | 185,339,000 | 87,143,000 | |||||||||||||||||||||
Senior Unsecured Notes | Senior Unsecured Debenture Due February 2027 | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Par value | CAD | CAD 300,000,000 | ||||||||||||||||||||||
Maturity date | 4.09% | ||||||||||||||||||||||
Debt instrument, sales price ratio | 0.99929 | ||||||||||||||||||||||
Senior Unsecured Notes | Bella Vista Water Loans | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Repayment of long-term debt | $ 707,000 | ||||||||||||||||||||||
Bonds | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Par value | $ 500,000,000 | ||||||||||||||||||||||
Senior Debt | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Par value | CAD | CAD 750,000,000 | ||||||||||||||||||||||
Debt instrument, number of tranches | Tranche | 6 | ||||||||||||||||||||||
Debt instrument, weighted average life | 15 years | ||||||||||||||||||||||
Weighted average coupon | 4.00% | ||||||||||||||||||||||
Effective weighted average interest rate | 3.60% | ||||||||||||||||||||||
Letter of Credit | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD 50,000,000 | $ 30,000,000 | |||||||||||||||||||||
Debt instrument, term | 1 year | ||||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Weighted average coupon | 0.00% | 0.00% | |||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | APUC Senior Unsecured Revolving Facility Maturing November 2017 | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD | CAD 65,000,000 | CAD 165,000,000 | |||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | Liberty Utilities Senior Unsecured Revolving Facility Maturing September 2018 | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 200,000,000 | ||||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | Empire Revolving Credit Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 200,000,000 | ||||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | Liberty Power Bilateral Revolving Credit Facility Maturing August 2018 | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | $ 350,000,000 | |||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | St. Damase Wind Facility Revolving Credit Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 4,000,000 | ||||||||||||||||||||||
Amount draw on credit facility | 3,900,000 | ||||||||||||||||||||||
Revolving Credit Facility | Senior Unsecured Notes | Algonquin Power Senior Unsecured Revolving Facility Maturing July 2019 | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD | CAD 600,000,000 | CAD 150,000,000 | |||||||||||||||||||||
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 | ||||||||||||||||||||||
Line of Credit | Acquisition Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Proceed from long-term lines of credit | $ 1,336,440,000 | ||||||||||||||||||||||
Debt instrument, cash held by paying agent | 1,495,774,000 | ||||||||||||||||||||||
Line of Credit | Bridge Loan | Acquisition Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Proceed from long-term lines of credit | $ 1,336,440,000 | $ 1,336,440,000 | |||||||||||||||||||||
Corporate Term Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Repayment of debt | CAD | CAD 100,000,000 | ||||||||||||||||||||||
Subsequent Event | Revolving Credit Facility | Senior Unsecured Notes | Empire Revolving Credit Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | ||||||||||||||||||||||
Subsequent Event | Revolving Credit Facility | Senior Unsecured Notes | Algonquin Power Senior Unsecured Revolving Facility Maturing July 2019 | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | CAD | CAD 200,000,000 | ||||||||||||||||||||||
Park Water Company | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | CAD | CAD 146,727,000 | ||||||||||||||||||||||
Park Water Company | Bonds | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | $ 63,000,000 | $ 65,000,000 | |||||||||||||||||||||
Park Water Company | Revolving Credit Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | $ 4,250,000 | ||||||||||||||||||||||
Park Water Company | Line of Credit | Non-Revolving Term Credit Facility | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | $ 22,500,000 | ||||||||||||||||||||||
Empire | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | CAD | CAD 1,218,563,000 | ||||||||||||||||||||||
Empire | U.S. Dollar Senior Unsecured Utility Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | $ 102,000,000 | ||||||||||||||||||||||
Debt instrument, number of tranches | Tranche | 2 | ||||||||||||||||||||||
Empire | Secured Utility Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | $ 733,000,000 | ||||||||||||||||||||||
Debt instrument, number of tranches | Tranche | 10 | ||||||||||||||||||||||
Deerfield SponsorCo | Construction Loans | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Long-term debt | $ 262,219,000 | ||||||||||||||||||||||
Minimum | Senior Debt | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Debt instrument, term | 3 years | ||||||||||||||||||||||
Minimum | Empire | U.S. Dollar Senior Unsecured Utility Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Maturity date | 6.70% | ||||||||||||||||||||||
Minimum | Empire | Secured Utility Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Maturity date | 3.58% | ||||||||||||||||||||||
Maximum | Senior Debt | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Debt instrument, term | 30 years | ||||||||||||||||||||||
Maximum | Empire | U.S. Dollar Senior Unsecured Utility Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Maturity date | 5.80% | ||||||||||||||||||||||
Maximum | Empire | Secured Utility Notes | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Maturity date | 6.82% | ||||||||||||||||||||||
Commercial Paper | Empire | |||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||
Short term commercial paper program assumed in acquisition | $ 150,000 |
- Principal Payments (Detail)
- Principal Payments (Detail) CAD in Thousands | Dec. 31, 2017CAD |
Long-term Debt, Fiscal Year Maturity [Abstract] | |
2,018 | CAD 279,724 |
2,019 | 179,107 |
2,020 | 391,025 |
2,021 | 152,626 |
2,022 | 492,343 |
Thereafter | 2,331,327 |
Total, including adjustment | CAD 3,826,152 |
Pension and other post-retire81
Pension and other post-retirement benefits - Additional Information (Detail) CAD in Thousands, $ in Thousands | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2017USD ($) | |
Employee Benefits Disclosure [Line Items] | |||||
Defined contribution pension plan cost | CAD 9,387 | CAD 5,223 | |||
Accumulated benefit obligation for pension plan | 614,840 | 317,025 | |||
Defined benefit plan, amounts recognized in other comprehensive income (loss), net prior service cost (credit) | $ | $ 2,217 | ||||
Net actuarial gain (loss) for defined benefit pension plan that will be amortized from accumulated other comprehensive income over next fiscal year | $ | $ 8,204 | ||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | $ | $ 2,354 | ||||
Gain on curtailment | $ | $ 853 | ||||
Pension Plans | |||||
Employee Benefits Disclosure [Line Items] | |||||
Expected employer contributions for next year | 26,686 | ||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (49,785) | (6,773) | |||
Gain on curtailment | (1,129) | 0 | |||
Other Postretirement Benefit Plans, Defined Benefit | |||||
Employee Benefits Disclosure [Line Items] | |||||
Expected employer contributions for next year | 4,898 | ||||
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | (13,321) | 2,870 | |||
Gain on curtailment | CAD (6) | CAD 0 |
Pension and other post-retire82
Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) CAD in Thousands, $ in Thousands | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | |
Change in projected benefit obligation | |||
Actuarial (gain) loss | $ | $ (2,354) | ||
Gain on curtailment | $ | $ 853 | ||
Pension Plans | |||
Change in projected benefit obligation | |||
Projected benefit obligation, beginning of year | CAD 331,934 | CAD 269,382 | |
Projected benefit obligation assumed from business combination | 344,383 | 63,811 | |
Modifications to pension plan | 0 | (2,754) | |
Service cost | 17,869 | 8,435 | |
Interest cost | 27,346 | 13,029 | |
Actuarial (gain) loss | 49,785 | 6,773 | |
Contributions from retirees | 0 | 0 | |
Gain on curtailment | (1,129) | 0 | |
Benefits paid | (64,605) | (15,845) | |
Gain on foreign exchange | (48,546) | (10,897) | |
Projected benefit obligation, end of year | 657,037 | 331,934 | |
Change in plan assets | |||
Fair value of plan assets, beginning of year | 236,369 | 176,171 | |
Plan assets acquired in business combination | 247,741 | 44,258 | |
Actual return on plan assets | 82,096 | 17,221 | |
Employer contributions | 38,833 | 21,776 | |
Benefits paid | (64,605) | (15,845) | |
Loss on foreign exchange | (33,686) | (7,212) | |
Fair value of plan assets, end of year | 506,748 | 236,369 | |
Unfunded status | (150,289) | (95,565) | |
Non-current assets | 0 | 0 | |
Current liabilities | (1,080) | (436) | |
Non-current liabilities | (149,209) | (95,129) | |
Net amount recognized | (150,289) | (95,565) | |
Other Postretirement Benefit Plans, Defined Benefit | |||
Change in projected benefit obligation | |||
Projected benefit obligation, beginning of year | 83,097 | 76,565 | |
Projected benefit obligation assumed from business combination | 131,263 | 9,749 | |
Modifications to pension plan | 0 | (1,235) | |
Service cost | 6,280 | 2,916 | |
Interest cost | 8,621 | 3,525 | |
Actuarial (gain) loss | 13,321 | (2,870) | |
Contributions from retirees | 2,364 | 547 | |
Gain on curtailment | (6) | 0 | |
Benefits paid | (8,092) | (3,230) | |
Gain on foreign exchange | (14,834) | (2,870) | |
Projected benefit obligation, end of year | 222,014 | 83,097 | |
Change in plan assets | |||
Fair value of plan assets, beginning of year | 29,139 | 18,149 | |
Plan assets acquired in business combination | 122,900 | 10,563 | |
Actual return on plan assets | 25,612 | 1,854 | |
Employer contributions | 2,683 | 2,317 | |
Benefits paid | (5,901) | (2,683) | |
Loss on foreign exchange | (10,737) | (1,061) | |
Fair value of plan assets, end of year | 163,696 | 29,139 | |
Unfunded status | (58,318) | (53,958) | |
Non-current assets | 4,938 | 0 | |
Current liabilities | (1,471) | (1,242) | |
Non-current liabilities | (61,785) | (52,716) | |
Net amount recognized | CAD (58,318) | CAD (53,958) |
Pension and other post-retire83
Pension and other post-retirement benefits - Amounts Recognized in Accumulated Other Comprehensive Loss (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plans | ||
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward] | ||
Beginning balance, January 1 | CAD 31,975 | CAD 29,461 |
Additions to AOCI | (3,716) | 4,479 |
Reclassification to regulatory accounts | 1,584 | |
Amortization in current period | (1,290) | (1,965) |
Ending balance, December 31 | 28,553 | 31,975 |
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward] | ||
Beginning balance, January 1 | (6,959) | (4,970) |
Additions to AOCI | 0 | (2,754) |
Reclassification to regulatory accounts | 0 | |
Amortization in current period | 868 | 765 |
Ending balance, December 31 | (6,091) | (6,959) |
Actuarial losses (gains) - expected amortization in 2017 | (451) | |
Past service gains - expected amortizations in 2017 | 781 | |
Other Postretirement Benefit Plans, Defined Benefit | ||
Pension and Other Postretirement Benefit Plans, Accumulated Net Gains Losses [Roll Forward] | ||
Beginning balance, January 1 | (5,660) | (2,338) |
Additions to AOCI | (4,276) | (3,242) |
Reclassification to regulatory accounts | 4,902 | |
Amortization in current period | 321 | (80) |
Ending balance, December 31 | (4,713) | (5,660) |
Pension and Other Post Retirement Benefits Plans, Net Prior Service Cost Credit [Roll Forward] | ||
Beginning balance, January 1 | (888) | 0 |
Additions to AOCI | 0 | (1,235) |
Reclassification to regulatory accounts | 0 | |
Amortization in current period | 365 | 347 |
Ending balance, December 31 | (523) | CAD (888) |
Actuarial losses (gains) - expected amortization in 2017 | 214 | |
Past service gains - expected amortizations in 2017 | CAD 328 |
Pension and other post-retire84
Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.01% | 4.16% |
Expected return on assets | 7.01% | 6.41% |
Rate of compensation increase | 3.00% | 3.00% |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.12% | 4.23% |
Expected return on assets | 3.88% | 5.50% |
Health care cost trend rate | ||
Before Age 65 | 6.25% | 6.50% |
Age 65 and after | 6.25% | 6.50% |
Assumed Ultimate Medical Inflation Rate | 4.75% | 4.75% |
Year in which Ultimate Rate is reached | 2,023 | 2,023 |
Pension and other post-retire85
Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 3.43% | 3.95% |
Rate of compensation increase | 3.00% | 3.00% |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 3.60% | 4.04% |
Health care cost trend rate | ||
Before Age 65 | 6.25% | 6.25% |
Age 65 and after | 6.25% | 6.25% |
Assumed Ultimate Medical Inflation Rate | 4.75% | 4.75% |
Year in which Ultimate Rate is reached | 2,024 | 2,023 |
Pension and other post-retire86
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, 2017CAD | |
Retirement Benefits [Abstract] | |
Effect of a 1 percentage point increase in the HCCTR on year-end benefit obligation | CAD 38,047 |
Effect of a 1 percentage point increase in the HCCTR on total service and interest cost | 959 |
Effect of a 1 percentage point decrease in the HCCTR on, year-end benefit obligation | (30,057) |
Effect of a 1 percentage point decrease in the HCCTR on, total service and interest cost | CAD (765) |
Pension and other post-retire87
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, 2017 | Dec. 31, 2016 | |
Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | CAD 17,869 | CAD 8,435 |
Interest cost | 27,346 | 13,029 |
Expected return on plan assets | (32,244) | (14,854) |
Amortization of net actuarial loss (gain) | 1,480 | 1,965 |
Amortization of prior service credits | (808) | (765) |
Gain on curtailments and settlements | (1,394) | 0 |
Amortization of regulatory assets/liability | 15,179 | 4,698 |
Net benefit cost | 27,428 | 12,508 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 6,280 | 2,916 |
Interest cost | 8,621 | 3,525 |
Expected return on plan assets | (8,312) | (1,265) |
Amortization of net actuarial loss (gain) | (299) | 80 |
Amortization of prior service credits | (339) | (347) |
Gain on curtailments and settlements | (6) | 0 |
Amortization of regulatory assets/liability | 507 | 1,471 |
Net benefit cost | CAD 6,452 | CAD 6,380 |
Pension and other post-retire88
Pension and other post-retirement benefits - Target Plan Asset Allocation (Details) | Dec. 31, 2017 |
Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 70.00% |
Debt securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 30.00% |
Other | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 0.00% |
Minimum | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 49.00% |
Minimum | Debt securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 21.00% |
Maximum | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 79.00% |
Maximum | Debt securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target allocation percentage | 51.00% |
Pension and other post-retire89
Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) CAD in Thousands | Dec. 31, 2017CAD |
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 505,219 |
Debt securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Allocation percentage | 27.00% |
Debt securities | Level 1 | |
Defined Benefit Plan Disclosure [Line Items] | |
Fair value of plan assets | CAD 164,281 |
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 945 |
Pension and other post-retire90
Pension and other post-retirement benefits - Expected Benefit Payments (Detail) CAD in Thousands | Dec. 31, 2017CAD |
Pension Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
2,018 | CAD 43,445 |
2,019 | 39,037 |
2,020 | 40,132 |
2,021 | 45,060 |
2,022 | 45,108 |
2023-2027 | 236,821 |
Post Retirement Benefit Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
2,018 | 7,353 |
2,019 | 7,989 |
2,020 | 8,845 |
2,021 | 9,425 |
2,022 | 10,093 |
2023-2027 | CAD 58,844 |
Mandatorily redeemable Series91
Mandatorily redeemable Series C preferred shares (Details) - CAD CAD / shares in Units, CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Class of Stock [Line Items] | ||
Preferred stock redemption price per share (in CAD per share) | CAD 25 | |
Disclosure Estimated Dividend And Redemption Payments [Abstract] | ||
2,018 | CAD 279,724 | |
2,019 | 179,107 | |
2,020 | 391,025 | |
2,021 | 152,626 | |
2,022 | 492,343 | |
Thereafter to 2031 | 2,331,327 | |
Preferred shares series C, noncurrent | CAD 17,396 | CAD 17,552 |
Series C Preferred Stock | ||
Class of Stock [Line Items] | ||
Redeemable preferred stock issued, shares | 100 | |
Preferred stock redemption price per share (in CAD per share) | CAD 53,400 | |
Disclosure Estimated Dividend And Redemption Payments [Abstract] | ||
Less amounts representing interest | CAD (9,085) | |
Total Preferred shares series C | 18,464 | |
Less current portion | (1,068) | |
Preferred shares series C, noncurrent | CAD 17,396 | |
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] | ||
2,018 | CAD 1,068 | |
2,019 | 1,282 | |
2,020 | 1,344 | |
2,021 | 1,364 | |
2,022 | 1,390 | |
Thereafter to 2031 | 15,761 | |
Redemption amount | 5,340 | |
Estimated dividend and redemption payments | CAD 27,549 |
Other assets - Schedule of Othe
Other assets - Schedule of Other Assets (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Income tax receivable | CAD 7,485 | CAD 2,951 |
Deferred financing costs | 4,448 | 10,198 |
Other | 18,633 | 6,136 |
Total other assets | 30,566 | 19,285 |
Less current portion | (8,919) | (2,951) |
Other assets, noncurrent | CAD 21,647 | CAD 16,334 |
Other long-term liabilities a93
Other long-term liabilities and deferred credits - Schedule of Long-Term Liabilities and Deferred Credits (Detail) - CAD | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other Long-term Liabilities | |||
Advances in aid of construction (a) | CAD 78,636,000 | CAD 105,191,000 | |
Environmental remediation obligation (b) | 68,147,000 | 63,378,000 | CAD 71,529,000 |
Asset retirement obligations (c) | 55,406,000 | 24,822,000 | |
Customer deposits (d) | 35,790,000 | 14,881,000 | |
Unamortized investment tax credits (e) | 22,379,000 | 0 | |
Deferred credits (f) | 26,555,000 | 44,544,000 | |
Other | 55,779,000 | 22,790,000 | |
Other Liabilities | 342,692,000 | 275,606,000 | |
Less current portion | (57,586,000) | (43,157,000) | |
Other long-term liabilities | 285,106,000 | 232,449,000 | |
Transfers from advances in aid of construction to contributions in aid of construction | 13,626,000 | 23,986,000 | |
Estimated environmental remediation costs | 71,873,000 | 76,853,000 | |
Accrual for environmental loss contingencies to be incurred over next three years | CAD 25,186,000 | ||
Accrual for environmental loss contingencies, payment period | 28 years | ||
Amount of regulatory assets | CAD 551,134,000 | 291,964,000 | |
Obligation incurred | 2,604,000 | 393,000 | |
Changes of estimate | 1,476,000 | 1,022,000 | |
Accretion expense | 2,551,000 | 1,055,000 | |
Settlements | CAD 5,418,000 | ||
Minimum | |||
Other Long-term Liabilities | |||
Other liability repayment period | 5 years | ||
Accrual environmental cost | 2.20% | ||
Maximum | |||
Other Long-term Liabilities | |||
Other liability repayment period | 40 years | ||
Accrual environmental cost | 2.50% | ||
Environmental costs | |||
Other Long-term Liabilities | |||
Regulatory asset, expenditure recovery provided by regulator, time period | 7 years | ||
Amount of regulatory assets | CAD 103,761,000 | CAD 104,160,000 | |
Empire | |||
Other Long-term Liabilities | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligation | 31,717,000 | ||
Deerfield SponsorCo | |||
Other Long-term Liabilities | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligation | CAD 2,816,000 |
Other long-term liabilities a94
Other long-term liabilities and deferred credits - Changes in Environmental Remediation Obligation (Details) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Accrual for Environmental Loss Contingencies [Roll Forward] | ||
Opening Balance | CAD 63,378 | CAD 71,529 |
Remediation activities | (2,026) | (1,389) |
Accretion | 1,447 | 2,464 |
Changes in cash flow estimates | 2,135 | 2,088 |
Revision in assumptions | 7,686 | (9,101) |
Foreign exchange rate adjustment | (4,473) | (2,213) |
Closing Balance | CAD 68,147 | CAD 63,378 |
Convertible Unsecured Subordi95
Convertible Unsecured Subordinated Debentures - Schedule of Debt (Details) | 12 Months Ended | ||||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017$ / shares | Mar. 14, 2017 | Mar. 01, 2016CAD | |
Debt Instrument [Line Items] | |||||
Maturity date | 2.33% | ||||
Convertible Subordinated Debt | Convertible Unsecured Subordinated Debentures | |||||
Debt Instrument [Line Items] | |||||
Maturity date | 5.00% | 5.00% | |||
Conversion price (CAD per share) | $ / shares | $ 10.60 | ||||
Convertible Unsecured Subordinated Debentures [Roll Forward] | |||||
Carrying value at December 31, 2016 | CAD 358,619,000 | ||||
Receipt of Final instalment, net of deferred financing costs | 743,881,000 | CAD 357,694,000 | |||
Amortization of deferred financing costs | 1,134,000 | 925,000 | |||
Conversion to common shares | (1,102,416,000) | ||||
Carrying value at December 31, 2017 | 1,218,000 | CAD 358,619,000 | |||
Par value | CAD 1,277,000 | CAD 1,150,000,000 |
Convertible Unsecured Subordi96
Convertible Unsecured Subordinated Debentures - Narrative (Details) | Mar. 01, 2016CADsharestrading_daysCAD / instrument | Dec. 31, 2017CADshares | Dec. 31, 2016CADshares | Mar. 14, 2017 | Feb. 02, 2017 |
Debt Instrument [Line Items] | |||||
Maturity date | 2.33% | ||||
Deferred financing costs | CAD 4,448,000 | CAD 10,198,000 | |||
Debt conversion, shares issued (in shares) | shares | 108,370,081 | 0 | |||
Convertible Subordinated Debt | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, effective interest rate | 0.00% | ||||
Convertible Subordinated Debt | Convertible Unsecured Subordinated Debentures | |||||
Debt Instrument [Line Items] | |||||
Face value | CAD 1,150,000,000 | CAD 1,277,000 | |||
Maturity date | 5.00% | 5.00% | |||
Debt instrument, convertible, price per instrument (CAD per debenture) | CAD / instrument | 1,000,000 | ||||
Debt instrument, convertible, price per instrument paid at closing (CAD per debenture) | CAD / instrument | 333,000 | ||||
Debt instrument, convertible, price per instrument outstanding (CAD per debenture) | CAD / instrument | 667,000 | ||||
Proceeds from issuance of debt | CAD 743,881,000 | CAD 357,694,000 | |||
interest expense | CAD 9,373,000 | CAD 48,205,000 | |||
Debt instrument, convertible, number of equity instruments (in shares) | shares | 108,490,566 | ||||
Debt conversion, shares issued (in shares) | shares | 108,370,081 | ||||
Debt instrument, convertible debt, percentage of shares issued | 0.999 | ||||
Percentage of weighted average trading price | 95.00% | ||||
Threshold consecutive trading days | trading_days | 20 |
Shareholders' capital - Common
Shareholders' capital - Common Shares (Detail) - shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Common Shares Rollforward | ||
Beginning balance (in shares) | 274,087,018 | 255,869,419 |
Public offering and subscription receipts (in shares) | 43,470,000 | 12,938,457 |
Debt conversion, shares issued (in shares) | 108,370,081 | 0 |
Dividend reinvestment plan (in shares) | 3,905,848 | 2,322,618 |
Exercise of share-based awards | 1,932,988 | 2,956,524 |
Ending balance (in shares) | 431,765,935 | 274,087,018 |
Shareholders' capital - Additio
Shareholders' capital - Additional Information (Detail) CAD / shares in Units, CAD in Thousands | Nov. 10, 2017CADCAD / sharesshares | Dec. 29, 2014CADCAD / sharesshares | Mar. 02, 2018shares | Jun. 30, 2016shares | Dec. 31, 2017CADRightvoteCAD / sharesshares | Dec. 31, 2016CADCAD / sharesshares |
Stockholders Equity Note [Line Items] | ||||||
Number of entitled votes per common share | vote | 1 | |||||
Number of voting rights per share | Right | 1 | |||||
Discount rate on share purchases | 50.00% | |||||
Common shares issued (in shares) | 43,470,000 | 12,938,457 | ||||
Discount rate on share purchases under dividend reinvestment plan | 5.00% | |||||
Carrying amount | CAD | CAD 213,805 | CAD 213,805 | ||||
Preferred stock redemption price per share (in CAD per share) | CAD / shares | CAD 25 | |||||
Total share-based compensation expense | CAD | CAD 10,804 | 5,675 | ||||
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 (in shares) | 1,063,572 | |||||
Employee Stock Option | ||||||
Stockholders Equity Note [Line Items] | ||||||
Total share-based compensation expense | CAD | CAD 3,990 | 3,006 | ||||
Unrecognized compensation costs, non-vested options | CAD | CAD 2,796 | |||||
Unrecognized compensation costs, non-vested options, period of recognition | 1 year 7 months 10 days | |||||
Stock Option Plans | Maximum | ||||||
Stockholders Equity Note [Line Items] | ||||||
Percentage of shares reserves under plan (must not exceed) | 8.00% | |||||
Performance Share Units | ||||||
Stockholders Equity Note [Line Items] | ||||||
Maximum aggregate number of shares reserved for future issuance (in shares) | 7,000,000 | |||||
Performance share units granting period | 3 years | |||||
Percentage of shares issued on number of PSU grants, minimum | 2.00% | |||||
Percentage of shares issued on number of PSU grants, maximum | 237.00% | |||||
Employee share purchase | ||||||
Stockholders Equity Note [Line Items] | ||||||
Total share-based compensation expense | CAD | CAD 568 | CAD 238 | ||||
Vesting period of matching contribution shares | 1 year | |||||
Maximum aggregate number of shares reserved for future issuance (in shares) | 2,000,000 | |||||
Common stock, shares issued (in shares) | 283,523 | 144,264 | ||||
Deferred Share Units | ||||||
Stockholders Equity Note [Line Items] | ||||||
Maximum aggregate number of shares reserved for future issuance (in shares) | 1,000,000 | |||||
Shares issued during period (in shares) | 293,906 | 224,663.24 | ||||
Performance share units | ||||||
Stockholders Equity Note [Line Items] | ||||||
Total share-based compensation expense | CAD | CAD 5,475 | CAD 1,748 | ||||
Unrecognized compensation costs, non-vested awards | CAD | CAD 8,471 | |||||
Unrecognized compensation costs, non-vested options, period of recognition | 1 year 10 months 2 days | |||||
Series A Preferred Stock | ||||||
Stockholders Equity Note [Line Items] | ||||||
Preferred stock issued (in shares) | 4,800,000 | 4,800,000 | ||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 25 | CAD 25 | ||||
Carrying amount | CAD | CAD 116,546 | CAD 116,546 | ||||
Fixed cumulative annual dividend per share (CAD per share) | CAD / shares | CAD 1.125 | |||||
Subsequent yield period | 5 years | |||||
Preferred stock, Subsequent redemption period | 5 years | |||||
Series C Preferred Stock | ||||||
Stockholders Equity Note [Line Items] | ||||||
Preferred stock redemption price per share (in CAD per share) | CAD / shares | CAD 53,400 | |||||
Redeemable preferred stock issued (in shares) | 100 | |||||
Series D Preferred Stock | ||||||
Stockholders Equity Note [Line Items] | ||||||
Preferred stock issued (in shares) | 4,000,000 | 4,000,000 | ||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 25 | CAD 25 | ||||
Carrying amount | CAD | CAD 97,259 | CAD 97,259 | ||||
Fixed cumulative annual dividend per share (CAD per share) | CAD / shares | CAD 1.25 | |||||
Subsequent yield period | 5 years | |||||
Preferred stock, Subsequent redemption period | 5 years | |||||
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 (in shares) | 3,316,583 | |||||
Issuance of convertible debentures, net of costs | CAD | CAD 33,000 | |||||
Additional shares issued under dividend reinvestment plan (in shares) | 252,011 | |||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 9.95 | |||||
Emera | Odell Wind Facility | Subscription receipts | ||||||
Stockholders Equity Note [Line Items] | ||||||
Common shares issued (in shares) | 8,708,170 | |||||
Issuance of convertible debentures, net of costs | CAD | CAD 77,503 | |||||
Additional shares issued under dividend reinvestment plan (in shares) | 661,693 | |||||
Shares issued, price per share (CAD per share) | CAD / shares | CAD 8.90 | |||||
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% | |||||
Public Stock Offering [Member] | ||||||
Stockholders Equity Note [Line Items] | ||||||
Sale of stock, price per share (CAD per share) | CAD / shares | CAD 13.25 | |||||
Payments of Stock Issuance Costs | CAD | CAD 24,342 | |||||
Public Stock Offering [Member] | Common shares | ||||||
Stockholders Equity Note [Line Items] | ||||||
Number of shares issued pursuant to public offering | 43,470,000 | |||||
Cash proceeds from issuance of shares | CAD | CAD 576,000 | |||||
Payments Of Stock Issuance Costs, Net of Tax | CAD | CAD 17,895 |
Shareholder's capital - Share-B
Shareholder's capital - Share-Based Compensation Expense (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | CAD 10,804 | CAD 5,675 |
Share options | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | 3,990 | 3,006 |
Directors deferred share units | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | 771 | 683 |
Employee share purchase | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | 568 | 238 |
Performance share units | ||
Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items] | ||
Share-based compensation expense | CAD 5,475 | CAD 1,748 |
Shareholders' capital - Fair Va
Shareholders' capital - Fair Value of Share Options Granted (Detail) | 12 Months Ended | |
Dec. 31, 2017CAD / shares | Dec. 31, 2016$ / shares | |
Equity [Abstract] | ||
Risk-free interest rate | 1.40% | 0.90% |
Expected volatility | 25.00% | 23.00% |
Expected dividend yield | 4.30% | 4.50% |
Expected life | 5 years 6 months | 5 years 6 months |
Weighted average grant date fair value per option (CAD per share) | (per share) | CAD 1.45 | $ 1.26 |
Shareholders' capital - Stock O
Shareholders' capital - Stock Option Activity (Detail) CAD / shares in Units, CAD in Thousands | 12 Months Ended | ||||
Dec. 31, 2017CADCAD / sharesshares | Dec. 31, 2017CAD$ / sharesCAD / sharesshares | Dec. 31, 2016CADCAD / sharesshares | Dec. 31, 2016$ / shares | Dec. 31, 2015CADCAD / sharesshares | |
Number of awards | |||||
Beginning balance (in shares) | shares | 6,045,014 | 7,164,652 | |||
Granted (in shares) | shares | 2,328,343 | 2,596,025 | |||
Exercised (in shares) | shares | (1,634,501) | (3,715,663) | |||
Ending balance (in shares) | shares | 6,738,856 | 6,045,014 | 7,164,652 | ||
Exercisable (in shares) | shares | 2,448,689 | 2,448,689 | |||
Weighted average exercise price | |||||
Beginning balance (CAD per share) | CAD / shares | CAD 9.64 | CAD 6.92 | |||
Granted (CAD per share) | CAD / shares | 12.82 | 10.85 | |||
Exercised (CAD per share) | $ / shares | $ 7.81 | $ 5.25 | |||
Ending balance (CAD per share) | CAD / shares | 11.18 | CAD 9.64 | CAD 6.92 | ||
Exercisable (CAD per share) | CAD / shares | CAD 10.03 | $ 10.03 | |||
Additional Disclosures | |||||
Outstanding shares, weighted average remaining contractual term | 6 years 3 months 25 days | 6 years 3 months 7 days | 4 years 8 months 25 days | ||
Granted, weighted average remaining contractual term | 8 years | 8 years | |||
Exercised shares, weighted average remaining contractual term | 3 years 9 months 4 days | 2 years 21 days | |||
Exercisable , weighted average remaining contractual term | 5 years 7 months 10 days | ||||
Beginning balance, aggregate intrinsic value | CAD | CAD 10,595 | CAD 28,561 | |||
Granted, aggregate intrinsic value | CAD | 0 | ||||
Exercised, aggregate intrinsic value | CAD | 7,696 | 20,790 | |||
Ending balance, aggregate intrinsic value | CAD | 19,380 | CAD 10,595 | CAD 28,561 | ||
Exercisable , aggregate intrinsic value | CAD | CAD 9,473,719 | $ 9,473,719 |
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Number of awards | |||
Beginning balance (in shares) | 578,988 | 564,116 | |
Granted (in shares) | 811,974 | 219,315 | |
Exercised (in shares) | (374,973) | (181,875) | |
Forfeited (in shares) | (60,961) | (22,568) | |
Ending balance (in shares) | 955,028 | 578,988 | 564,116 |
Exercisable (in shares) | 172,031 | ||
Weighted average grant-date fair value | |||
Beginning balance (CAD per share) | CAD 9.82 | CAD 7.59 | |
Granted (CAD per share) | 13.54 | 11.62 | |
Exercised (CAD per share) | 8.33 | 8.29 | |
Forfeited (CAD per share) | 12.61 | 9.64 | |
Ending balance (CAD per share) | 12.30 | CAD 9.82 | CAD 7.59 |
Exercisable (CAD per share) | CAD 9.75 | ||
Additional Disclosures | |||
Outstanding, Weighted average remaining contractual term | 1 year 10 months 2 days | 1 year 8 months 26 days | 1 year 7 months 17 days |
Granted, Weighted average remaining contractual term | 2 years | 2 years | |
Outstanding, aggregate intrinsic value | CAD 13,428 | CAD 6,595 | CAD 6,155 |
Granted, aggregate intrinsic value | 0 | 0 | |
Exercised, aggregate intrinsic value | 4,394 | 2,115 | |
Forfeited, aggregate intrinsic value | 0 | CAD 0 | |
Exercisable, aggregate intrinsic value | CAD 2,423 |
Accumulated other comprehens103
Accumulated other comprehensive income (loss) - Schedule of Accumulated Other Comprehensive Income (loss) (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning Balance | CAD 2,485,921 | CAD 2,291,864 |
Other comprehensive loss, net of tax | (253,774) | (38,636) |
Ending Balance | 4,165,037 | 2,485,921 |
Foreign currency cumulative translation | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning Balance | 200,328 | 261,357 |
OCI (loss) before reclassifications | (200,400) | (61,029) |
Amounts reclassified | 0 | 0 |
Other comprehensive loss, net of tax | (200,400) | (61,029) |
Ending Balance | (72) | 200,328 |
Unrealized gain on cash flow hedges | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning Balance | 66,083 | 39,329 |
OCI (loss) before reclassifications | 8,714 | 34,308 |
Amounts reclassified | (6,805) | (7,554) |
Other comprehensive loss, net of tax | 1,909 | 26,754 |
Ending Balance | 67,992 | 66,083 |
Net change on available-for-sale investments | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning Balance | 141 | (72) |
OCI (loss) before reclassifications | 0 | 213 |
Amounts reclassified | (141) | 0 |
Other comprehensive loss, net of tax | (141) | 213 |
Ending Balance | 0 | 141 |
Pension and post-employment actuarial changes | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning Balance | (11,625) | (13,877) |
OCI (loss) before reclassifications | 838 | 2,856 |
Amounts reclassified | (313) | (604) |
Other comprehensive loss, net of tax | 525 | 2,252 |
Ending Balance | (11,100) | (11,625) |
Accumulated OCI | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Beginning Balance | 254,927 | 286,737 |
OCI (loss) before reclassifications | (190,848) | (23,652) |
Amounts reclassified | (7,259) | (8,158) |
Other comprehensive loss, net of tax | (198,107) | (31,810) |
Ending Balance | CAD 56,820 | CAD 254,927 |
Dividends (Detail)
Dividends (Detail) - CAD CAD / shares in Units, CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Dividends [Line Items] | ||
Dividend declared for common share holders | CAD 242,509 | CAD 149,158 |
Cash dividend declared per common share (CAD per share) | CAD 0.6084 | CAD 0.5452 |
Series A Preferred Stock | ||
Dividends [Line Items] | ||
Dividends declared for preferred share holders | CAD 5,400 | CAD 5,400 |
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 | CAD 5,000 |
Dividend declared per preferred share (CAD per share) | CAD 1.2500 | CAD 1.2500 |
Related party transactions (Det
Related party transactions (Detail) CAD in Thousands, $ in Thousands | Oct. 14, 2016CAD | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) |
Emera | |||||
Transactions with Third Party [Line Items] | |||||
Amounts due from related party | $ 4,397 | $ 10,185 | |||
Amounts purchased from related party | 1,006 | 3,939 | |||
Reimbursement of expenses | CAD | CAD 680 | ||||
Amounts due to related party | 1,467 | 757 | |||
Equity Method Investee | |||||
Transactions with Third Party [Line Items] | |||||
Reimbursement of expenses | CAD | CAD 5,969 | CAD 3,313 | |||
Design, Engineering, Supply and Construction Agreement | Emera | |||||
Transactions with Third Party [Line Items] | |||||
Related party contract amount | $ 9,500 | ||||
Trafalgar Power Foreclosed Debt by Related Entity | Related Entity | |||||
Transactions with Third Party [Line Items] | |||||
Litigation settlement, amount | 10,083 | ||||
Reimbursement of legal fees | 2,900 | ||||
Gain related to litigation settlement | $ 6,600 |
Non-controlling Interests an106
Non-controlling Interests and Redeemable non-controlling Interest - Net Loss Attributable to Non-Controlling Interest (Details) CAD in Thousands, $ in Thousands | Sep. 18, 2017USD ($) | May 10, 2017USD ($) | Feb. 28, 2017USD ($) | Feb. 17, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD |
Noncontrolling Interest [Line Items] | ||||||||
Net effect of non-controlling interests | CAD 62,248 | CAD 38,550 | ||||||
Net loss attributable to redeemable non-controlling interest | (13,400) | (4,952) | ||||||
Non-controlling interests | 756,007 | 562,358 | ||||||
Other Noncontrolling Interests | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Net effect of non-controlling interests | (3,172) | (1,853) | ||||||
Non-controlling interests | 1,075 | 1,050 | ||||||
Class A Units | Class A Partnership Units | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Net effect of non-controlling interests | 52,020 | 35,451 | ||||||
Net loss attributable to redeemable non-controlling interest | (13,400) | (4,952) | ||||||
Non-controlling interests | CAD 754,932 | CAD 561,308 | ||||||
Great Bay Solar Facility | Partnership | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Partnership agreement, funded amount | $ | $ 42,750 | |||||||
Tax Investor | Great Bay Solar Facility | Partnership | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Partnership agreement, funded amount | $ | $ 59 | |||||||
Tax Investor | Bakersfield II Solar Facility | Partnership | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Partnership agreement, funded amount | $ | $ 9,800 | |||||||
Tax Investor | Deerfield Wind Project | Partnership | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Partnership agreement, funded amount | $ | $ 166,595 | |||||||
Tax Investor | Luning Solar Facility | Partnership | ||||||||
Noncontrolling Interest [Line Items] | ||||||||
Partnership agreement, funded amount | $ | $ 31,212 | $ 7,826 |
Non-controlling Interests an107
Non-controlling Interests and Redeemable non-controlling Interest - Change in Redeemable non-controlling Interest (Details) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Temporary Equity [Roll Forward] | ||
Opening balance | CAD 29,434 | CAD 25,751 |
Net loss attributable to redeemable non-controlling interest | (13,400) | (4,952) |
Contributions from redeemable non-controlling interests | 40,797 | 10,171 |
Dividends declared and distributions to redeemable non-controlling interest | (1,454) | (590) |
Foreign exchange | (3,249) | (946) |
Closing balance | CAD 52,128 | CAD 29,434 |
Income taxes - Additional Infor
Income taxes - Additional Information (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Canadian enacted statutory rate | 26.50% | 26.50% |
Valuation allowance for deferred tax assets | CAD 15,486 | CAD 21,656 |
Deferred taxes | 85,286 | CAD 28,675 |
Deferred income taxes, undistributed earnings of foreign subsidiaries | 188,348 | |
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Change In Tax Rate, Deferred Tax Asset, Provisional Income Tax Expense | 22,390 | |
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Change In Tax Rate, Deferred Tax Liability, Provisional Income Tax Benefit | CAD 411,409 |
Income taxes - Provision for In
Income taxes - Provision for Income Taxes (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Expected income tax expense at Canadian statutory rate | CAD 59,907 | CAD 34,317 |
Increase (decrease) resulting from: | ||
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates | (27,671) | (11,363) |
Non-controlling interests share of income | 24,708 | 13,973 |
Allowance for equity funds used during construction | (1,029) | (1,100) |
Capital gain rate differential | (919) | (3,612) |
Goodwill divestiture and permanent basis differences associated with Mountain Water condemnation | 7,059 | 0 |
Non-deductible acquisition costs | 18,091 | 1,996 |
Change in valuation allowance | (1,304) | 2,841 |
Tax credits | (8,162) | (477) |
Adjustment relating to prior periods | (30) | (711) |
U.S. tax reform | 22,390 | 0 |
Other | 2,154 | 1,272 |
Income tax expense | CAD 95,194 | CAD 37,136 |
Income taxes - Income (Loss) Be
Income taxes - Income (Loss) Before Taxes (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items] | ||
Income/(loss) before taxes | CAD 226,040 | CAD 129,510 |
Canadian operations | ||
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items] | ||
Income/(loss) before taxes | (3,269) | 29 |
U.S. operations | ||
Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items] | ||
Income/(loss) before taxes | CAD 229,309 | CAD 129,481 |
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, 2017 | Dec. 31, 2016 | |
Income Tax Expenses [Line Items] | ||
Income tax expenses, current | CAD 9,908 | CAD 8,461 |
Income tax expenses, deferred | 85,286 | 28,675 |
Income tax expense | 95,194 | 37,136 |
Canada | ||
Income Tax Expenses [Line Items] | ||
Income tax expenses, current | 4,277 | 7,533 |
Income tax expenses, deferred | (18,390) | (10,501) |
Income tax expense | (14,113) | (2,968) |
United States | ||
Income Tax Expenses [Line Items] | ||
Income tax expenses, current | 5,631 | 928 |
Income tax expenses, deferred | 103,676 | 39,176 |
Income tax expense | CAD 109,307 | CAD 40,104 |
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, 2017 | Dec. 31, 2016 |
Deferred tax assets: | ||
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs | CAD 412,327 | CAD 459,436 |
Pension and OPEB | 54,744 | 57,751 |
Acquisition-related costs | 2,008 | 3,612 |
Environmental obligation | 18,570 | 25,683 |
Reserves and other non-deductible costs | 38,453 | 11,390 |
Regulatory liabilities | 193,942 | 76,315 |
Other | 20,555 | 14,374 |
Total deferred income tax assets | 740,599 | 648,561 |
Less valuation allowance | (15,486) | (21,656) |
Total deferred tax assets | 725,113 | 626,905 |
Deferred tax liabilities: | ||
Property, plant and equipment | (838,110) | (562,124) |
Intangible assets | (8,067) | (8,035) |
Outside basis in partnership | (157,463) | (187,717) |
Regulatory accounts | (143,090) | (108,506) |
Financial derivatives | (1,230) | (17,649) |
Other | 0 | (1,008) |
Total deferred tax liabilities | (1,147,960) | (885,039) |
Net deferred tax liabilities | (422,847) | (258,134) |
Deferred tax assets | 76,972 | 30,005 |
Deferred tax liabilities | CAD (499,819) | CAD (288,139) |
Income taxes - Non Capital Loss
Income taxes - Non Capital Losses Carry Forwards (Detail) CAD in Thousands | Dec. 31, 2017CAD |
2020 and onwards | |
Capital Loss Carryforwards [Line Items] | |
Non-capital loss carryforwards | CAD 1,247,448 |
Basic and diluted net earnin114
Basic and diluted net earnings per share - Schedule of Earnings per Share (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Class of Stock [Line Items] | ||
Net earnings attributable to shareholders of APUC | CAD 193,094 | CAD 130,924 |
Series A and D Preferred shares dividend | 10,400 | 10,400 |
Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted | CAD 182,694 | CAD 120,524 |
Weighted average number of shares | ||
Basic (in shares) | 382,323,434 | 271,832,430 |
Effect of dilutive securities (in shares) | 3,662,714 | 2,244,602 |
Diluted (in shares) | 385,986,148 | 274,077,032 |
Series A Preferred Stock | ||
Class of Stock [Line Items] | ||
Series A and D Preferred shares dividend | CAD 5,400 | CAD 5,400 |
Series D Preferred Stock | ||
Class of Stock [Line Items] | ||
Series A and D Preferred shares dividend | CAD 5,000 | CAD 5,000 |
Basic and diluted net earnin115
Basic and diluted net earnings per share - Additional Information (Detail) - shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Options and Convertible Debentures | ||
Class of Stock [Line Items] | ||
Anti-dilutive convertible debentures (in shares) | 2,328,343 | 1,665,131 |
Segmented information - Additio
Segmented information - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2017business_unitcountry | |
Segment Reporting [Abstract] | |
Number of business units | business_unit | 2 |
Number of countries in which entity operates | country | 2 |
Segmented information - Results
Segmented information - Results of Operations and Assets for Segments (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue | ||
Revenue | CAD 1,977,809 | CAD 1,096,018 |
Fuel, power and water purchased | 510,400 | 295,315 |
Net revenue | 1,467,409 | 800,703 |
Operating expenses | 598,658 | 333,001 |
Administrative expenses | 64,466 | 46,349 |
Depreciation and amortization | 326,447 | 186,899 |
Gain on foreign exchange | 373 | (436) |
Operating income | 477,465 | 234,890 |
Interest expense | 202,631 | 131,592 |
Interest, dividend, equity and other income | (11,989) | (10,573) |
Other expenses (gain) | 60,783 | (15,639) |
Earnings (loss) before income taxes | 226,040 | 129,510 |
Property, plant and equipment | 7,909,493 | 4,889,946 |
Equity-method investees | 40,479 | 64,419 |
Total assets | 10,533,635 | 8,249,460 |
Capital expenditures | 740,023 | 405,743 |
Liberty Power Group | ||
Revenue | ||
Revenue | 300,173 | 265,949 |
Fuel, power and water purchased | 25,384 | 21,260 |
Net revenue | 274,789 | 244,689 |
Operating expenses | 86,675 | 72,346 |
Administrative expenses | 20,777 | 19,656 |
Depreciation and amortization | 103,038 | 80,094 |
Gain on foreign exchange | 0 | 0 |
Operating income | 64,299 | 72,593 |
Interest expense | 47,565 | 21,847 |
Interest, dividend, equity and other income | (3,723) | 32 |
Other expenses (gain) | 2,282 | (14,403) |
Earnings (loss) before income taxes | 18,175 | 65,117 |
Property, plant and equipment | 2,818,697 | 2,455,336 |
Equity-method investees | 37,273 | 59,021 |
Total assets | 3,103,999 | 2,771,651 |
Capital expenditures | 211,328 | 141,420 |
Liberty Utilities Group | ||
Revenue | ||
Revenue | 1,677,636 | 830,069 |
Fuel, power and water purchased | 485,016 | 274,055 |
Net revenue | 1,192,620 | 556,014 |
Operating expenses | 511,983 | 260,595 |
Administrative expenses | 42,900 | 26,272 |
Depreciation and amortization | 222,088 | 105,448 |
Gain on foreign exchange | 0 | 0 |
Operating income | 415,649 | 163,699 |
Interest expense | 126,790 | 50,671 |
Interest, dividend, equity and other income | (5,449) | (5,282) |
Other expenses (gain) | (4,250) | (11,690) |
Earnings (loss) before income taxes | 298,558 | 130,000 |
Property, plant and equipment | 5,047,454 | 2,390,047 |
Equity-method investees | 2,784 | 2,314 |
Total assets | 7,299,576 | 5,388,966 |
Capital expenditures | 528,695 | 264,323 |
Corporate | ||
Revenue | ||
Revenue | 0 | 0 |
Fuel, power and water purchased | 0 | 0 |
Net revenue | 0 | 0 |
Operating expenses | 0 | 60 |
Administrative expenses | 789 | 421 |
Depreciation and amortization | 1,321 | 1,357 |
Gain on foreign exchange | 373 | (436) |
Operating income | (2,483) | (1,402) |
Interest expense | 28,276 | 59,074 |
Interest, dividend, equity and other income | (2,817) | (5,323) |
Other expenses (gain) | 62,751 | 10,454 |
Earnings (loss) before income taxes | (90,693) | (65,607) |
Property, plant and equipment | 43,342 | 44,563 |
Equity-method investees | 422 | 3,084 |
Total assets | 130,060 | 88,843 |
Capital expenditures | CAD 0 | CAD 0 |
Segmented information - Informa
Segmented information - Information on Operations by Geographic Area (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | ||
Revenue | CAD 1,977,809 | CAD 1,096,018 |
Property, plant and equipment | 7,909,493 | 4,889,946 |
Intangible assets | 64,108 | 64,989 |
Canada | ||
Segment Reporting Information [Line Items] | ||
Revenue | 95,326 | 100,403 |
Property, plant and equipment | 568,693 | 558,271 |
Intangible assets | 34,654 | 36,611 |
United States | ||
Segment Reporting Information [Line Items] | ||
Revenue | 1,882,483 | 995,615 |
Property, plant and equipment | 7,340,800 | 4,331,675 |
Intangible assets | CAD 29,454 | CAD 28,378 |
Commitments and contingencies -
Commitments and contingencies - Estimates of Future Commitments (Detail) CAD in Thousands, $ in Thousands | Jun. 22, 2017USD ($) | May 06, 2014USD ($) | Jan. 31, 2016USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD |
Commitments Disclosure [Line Items] | |||||
Year 1 | CAD 263,772 | ||||
Year 2 | 188,441 | ||||
Year 3 | 158,641 | ||||
Year 4 | 140,628 | ||||
Year 5 | 135,237 | ||||
Thereafter | 1,012,025 | ||||
Total | 1,898,744 | ||||
Power purchase | |||||
Commitments Disclosure [Line Items] | |||||
Year 1 | 74,025 | ||||
Year 2 | 48,344 | ||||
Year 3 | 49,940 | ||||
Year 4 | 50,214 | ||||
Year 5 | 50,495 | ||||
Thereafter | 254,380 | ||||
Total | 527,398 | ||||
Gas supply and service agreements | |||||
Commitments Disclosure [Line Items] | |||||
Year 1 | 91,425 | ||||
Year 2 | 66,848 | ||||
Year 3 | 51,809 | ||||
Year 4 | 33,161 | ||||
Year 5 | 28,411 | ||||
Thereafter | 97,489 | ||||
Total | 369,143 | ||||
Service agreements | |||||
Commitments Disclosure [Line Items] | |||||
Year 1 | 47,695 | ||||
Year 2 | 47,211 | ||||
Year 3 | 48,529 | ||||
Year 4 | 48,827 | ||||
Year 5 | 46,548 | ||||
Thereafter | 435,093 | ||||
Total | 673,903 | ||||
Capital projects | |||||
Commitments Disclosure [Line Items] | |||||
Year 1 | 41,054 | ||||
Year 2 | 17,064 | ||||
Year 3 | 65 | ||||
Year 4 | 65 | ||||
Year 5 | 65 | ||||
Thereafter | 16 | ||||
Total | 58,329 | ||||
Operating leases | |||||
Commitments Disclosure [Line Items] | |||||
Year 1 | 9,573 | ||||
Year 2 | 8,974 | ||||
Year 3 | 8,298 | ||||
Year 4 | 8,361 | ||||
Year 5 | 9,718 | ||||
Thereafter | 225,047 | ||||
Total | CAD 269,971 | ||||
Lawsuit vs. Mountain Water Company and City of Missoula [Member] | |||||
Commitments Disclosure [Line Items] | |||||
Fair value of condemned property | $ | $ 88,600 | ||||
Litigation settlement, amount | $ | $ 83,863 | ||||
Gain on long-lived assets | $ | $ 4,370 | ||||
Mountain Water Company [Member] | |||||
Commitments Disclosure [Line Items] | |||||
Amount permitted for hold-back | $ | $ 14,400 |
Non-cash operating items - Chan
Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - CAD CAD in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure Changes In Non Cash Operating Items [Abstract] | ||
Accounts receivable | CAD (18,502) | CAD 6,612 |
Fuel and natural gas in storage | (1,970) | 6,877 |
Supplies and consumable inventory | 1,392 | 692 |
Income taxes receivable | 1,674 | 145 |
Prepaid expenses | (897) | (6,161) |
Accounts payable | (23,178) | 24,524 |
Accrued liabilities | 25,122 | (9,454) |
Current income tax liability | (3,432) | (4,552) |
Net regulatory assets and liabilities | (54,235) | (14,979) |
Changes in non-cash operating items | CAD (74,026) | CAD 3,704 |
Financial instruments - Fair V
Financial instruments - Fair Value of Financial Instruments (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Cross currency swap | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | CAD 72,023 | |
Foreign exchange forward | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 432 | |
Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 3,422 | |
Interest rate swaps | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 10,613 | |
Level 1 | ||
Fair Value of Financial Instruments [Line Items] | ||
Long-term debt | 817,895 | CAD 517,637 |
Convertible debentures | 1,277 | 455,975 |
Total financial liabilities | 819,172 | 973,612 |
Level 2 | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 47,912 | 47,933 |
Derivative financial instruments, assets | 8,041 | 66,316 |
Total financial assets | 55,953 | 114,249 |
Long-term debt | 3,275,176 | 3,481,629 |
Convertible debentures | 0 | |
Derivative financial instruments, liabilities | 86,393 | 108,825 |
Total financial liabilities | 3,380,542 | 3,609,067 |
Level 2 | Energy contracts | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 0 | |
Level 2 | Energy contracts | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 137 | |
Level 2 | Energy contracts | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 39 | |
Level 2 | Cross currency swap | Designated as a hedge | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 72,023 | 95,404 |
Level 2 | Foreign exchange forward | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 432 | |
Level 2 | Foreign exchange forward | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 17,864 | |
Level 2 | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 92 | 359 |
Derivative financial instruments, liabilities | 3,286 | 36 |
Level 2 | Transmission congestion rights | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 7,812 | |
Level 2 | Interest rate swaps | Designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 10,613 | 13,385 |
Level 2 | Interest rate swaps | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 48,093 | |
Level 2 | Series C Preferred Stock | ||
Fair Value of Financial Instruments [Line Items] | ||
Convertible debentures | 18,613 | |
Preferred shares, Series C | 18,973 | |
Level 3 | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 0 | 0 |
Derivative financial instruments, assets | 79,490 | 84,554 |
Total financial assets | 79,490 | 84,554 |
Derivative financial instruments, liabilities | 97 | 0 |
Total financial liabilities | 97 | 0 |
Level 3 | Energy contracts | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 79,490 | 84,554 |
Derivative financial instruments, liabilities | 97 | |
Level 3 | Energy contracts | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 0 | |
Level 3 | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 0 | |
Level 3 | Transmission congestion rights | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 0 | |
Portion at Other than Fair Value Measurement [Member] | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 553 | 314 |
Carrying amount | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 41,873 | 38,183 |
Derivative financial instruments, assets | 87,531 | 150,870 |
Total financial assets | 129,404 | 189,053 |
Long-term debt | 3,863,296 | 3,913,415 |
Convertible debentures | 1,218 | 358,619 |
Derivative financial instruments, liabilities | 86,490 | 108,825 |
Total financial liabilities | 3,969,468 | 4,399,319 |
Carrying amount | Energy contracts | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 79,490 | 84,554 |
Derivative financial instruments, liabilities | 97 | |
Carrying amount | Energy contracts | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 137 | |
Carrying amount | Energy contracts | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 39 | |
Carrying amount | Cross currency swap | Designated as a hedge | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 72,023 | 95,404 |
Carrying amount | Foreign exchange forward | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 432 | |
Carrying amount | Foreign exchange forward | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 17,864 | |
Carrying amount | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 92 | 359 |
Derivative financial instruments, liabilities | 3,286 | 36 |
Carrying amount | Transmission congestion rights | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 7,812 | |
Carrying amount | Interest rate swaps | Designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 10,613 | 13,385 |
Carrying amount | Interest rate swaps | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 48,093 | |
Carrying amount | Series C Preferred Stock | ||
Fair Value of Financial Instruments [Line Items] | ||
Convertible debentures | 18,460 | |
Preferred shares, Series C | 18,464 | |
Fair Value | ||
Fair Value of Financial Instruments [Line Items] | ||
Notes receivable | 47,912 | 47,933 |
Derivative financial instruments, assets | 87,531 | 150,870 |
Total financial assets | 135,443 | 198,803 |
Long-term debt | 4,093,071 | 3,999,266 |
Convertible debentures | 1,277 | 455,975 |
Derivative financial instruments, liabilities | 86,490 | 108,825 |
Total financial liabilities | 4,199,811 | 4,582,679 |
Fair Value | Energy contracts | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 79,490 | 84,554 |
Derivative financial instruments, liabilities | 97 | |
Fair Value | Energy contracts | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 137 | |
Fair Value | Energy contracts | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 39 | |
Fair Value | Cross currency swap | Designated as a hedge | Net Investment Hedging | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 72,023 | 95,404 |
Fair Value | Foreign exchange forward | Not designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 432 | |
Fair Value | Foreign exchange forward | Not designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 17,864 | |
Fair Value | Commodity contracts for regulatory operations | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 92 | 359 |
Derivative financial instruments, liabilities | 3,286 | 36 |
Fair Value | Transmission congestion rights | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 7,812 | |
Fair Value | Interest rate swaps | Designated as a hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, liabilities | 10,613 | 13,385 |
Fair Value | Interest rate swaps | Designated as a hedge | Cash flow hedge | ||
Fair Value of Financial Instruments [Line Items] | ||
Derivative financial instruments, assets | 48,093 | |
Fair Value | Series C Preferred Stock | ||
Fair Value of Financial Instruments [Line Items] | ||
Convertible debentures | CAD 18,613 | |
Preferred shares, Series C | CAD 18,973 |
Financial instruments - Additi
Financial instruments - Additional Information (Detail) | Oct. 25, 2016USD ($) | Dec. 31, 2017CADMMBTUCAD / MWh | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2017USD ($)MMBTUCAD / MWh | Jan. 31, 2017CAD | Jan. 31, 2017USD ($) | Sep. 29, 2016CAD | Sep. 29, 2016USD ($) | Jan. 31, 2014CAD | Dec. 31, 2012CAD |
Derivative [Line Items] | |||||||||||
Commodity volumes, Gas | MMBTU | 15,457,678 | 15,457,678 | |||||||||
Effective portion of cash flow hedge, gain (loss) | CAD 8,714,000 | CAD 34,355,000 | |||||||||
Other comprehensive income, foreign currency loss | (21,648,000) | 0 | |||||||||
Other comprehensive income, foreign currency translation adjustment gain (loss) | (256,067,000) | (67,855,000) | |||||||||
Issuance of convertible debentures, net of costs | 743,881,000 | 357,694,000 | |||||||||
Total realized loss (gain) on derivative financial instruments | CAD (16,845,000) | 3,289,000 | |||||||||
Revenue collection period | 45 days | 45 days | |||||||||
Cash on hand | CAD 54,550,000 | ||||||||||
Available for drawn on senior debt facilities | 1,145,859,000 | ||||||||||
Utility Services | |||||||||||
Derivative [Line Items] | |||||||||||
Accounts receivable balances | $ | $ 204,380,000 | ||||||||||
Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Gain (loss) on derivative | (13,414,000) | 20,656,000 | |||||||||
Total realized loss (gain) on derivative financial instruments | (16,950,000) | 420,000 | |||||||||
Liberty Power Group | |||||||||||
Derivative [Line Items] | |||||||||||
Other comprehensive income, foreign currency translation adjustment gain (loss) | CAD 23,381,000 | 6,156,000 | |||||||||
Bonds | |||||||||||
Derivative [Line Items] | |||||||||||
Par value | $ | $ 500,000,000 | ||||||||||
Bonds | Plan | |||||||||||
Derivative [Line Items] | |||||||||||
Debt instrument, term | 10 years | 10 years | |||||||||
Long-term debt | CAD 135,000,000 | ||||||||||
Senior Unsecured Notes | |||||||||||
Derivative [Line Items] | |||||||||||
Long-term debt | 3,863,296,000 | 3,913,415,000 | |||||||||
Senior Unsecured Notes | Convertible Unsecured Subordinated Debentures | |||||||||||
Derivative [Line Items] | |||||||||||
Issuance of convertible debentures, net of costs | $ | $ 359,950,000 | ||||||||||
Senior Unsecured Notes | Liberty Power Group | 4.82% Senior Unsecured Notes | |||||||||||
Derivative [Line Items] | |||||||||||
Par value | CAD 150,000,000 | ||||||||||
Senior Unsecured Notes | Liberty Power Group | 4.65% Senior Unsecured Notes | |||||||||||
Derivative [Line Items] | |||||||||||
Par value | CAD 200,000,000 | ||||||||||
Senior Unsecured Notes | Liberty Power Group | Convertible Unsecured Subordinated Debentures | |||||||||||
Derivative [Line Items] | |||||||||||
Par value | CAD 300,000,000 | ||||||||||
Foreign exchange forward | |||||||||||
Derivative [Line Items] | |||||||||||
Notional amount | CAD 744,050,000 | $ 567,665,000 | CAD 47,225,000 | $ 38,400,000 | |||||||
Foreign exchange forward | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Total realized loss (gain) on derivative financial instruments | CAD (16,413,000) | 1,371,000 | |||||||||
Ten Year Foreign Exchange Forward | |||||||||||
Derivative [Line Items] | |||||||||||
Notional amount | $ | $ 250,000,000 | ||||||||||
Term of forward-starting interest rate swap | 10 years | ||||||||||
Derivative, forward interest rate | 1.8395% | ||||||||||
Thirty Year Foreign Exchange Forward | |||||||||||
Derivative [Line Items] | |||||||||||
Notional amount | $ | $ 250,000,000 | ||||||||||
Term of forward-starting interest rate swap | 30 years | ||||||||||
Derivative, forward interest rate | 2.5539% | ||||||||||
Forward contracts | |||||||||||
Derivative [Line Items] | |||||||||||
Commodity volumes, Gas | MMBTU | 12,420,000 | 12,420,000 | |||||||||
Other comprehensive income, foreign currency loss | CAD 432,000 | ||||||||||
Interest rate swaps | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Total realized loss (gain) on derivative financial instruments | 193,000 | 0 | |||||||||
Energy contracts | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Total realized loss (gain) on derivative financial instruments | CAD (730,000) | (951,000) | |||||||||
Cash flow hedge | Foreign exchange forward | |||||||||||
Derivative [Line Items] | |||||||||||
Effective portion of cash flow hedge, gain (loss) | $ | 718,000 | ||||||||||
Gain (loss) on derivative | $ | $ 36,667,000 | ||||||||||
Cash flow hedge | Interest rate swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Term of forward-starting interest rate swap | 10 years | 10 years | |||||||||
Effective portion of cash flow hedge, gain (loss) | CAD 2,771,000 | (3,726,000) | |||||||||
Minimum | |||||||||||
Derivative [Line Items] | |||||||||||
Forward price | CAD / MWh | 22.13 | 22.13 | |||||||||
Maximum | |||||||||||
Derivative [Line Items] | |||||||||||
Forward price | CAD / MWh | 121.56 | 121.56 | |||||||||
Weighted Average | |||||||||||
Derivative [Line Items] | |||||||||||
Forward price | CAD / MWh | 33.20 | 33.20 | |||||||||
Fair Value | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative financial instruments, assets | CAD 87,531,000 | 150,870,000 | |||||||||
Fair Value | Energy contracts | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative financial instruments, assets | 137,000 | ||||||||||
Fair Value | Cash flow hedge | Foreign exchange forward | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative financial instruments, assets | 17,864,000 | ||||||||||
Carrying amount | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative financial instruments, assets | 87,531,000 | 150,870,000 | |||||||||
Carrying amount | Energy contracts | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative financial instruments, assets | CAD 137,000 | ||||||||||
Carrying amount | Cash flow hedge | Foreign exchange forward | Not designated as a hedge | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative financial instruments, assets | 17,864,000 | ||||||||||
Credit Concentration Risk | Accounts Receivable | Liberty Power Group | |||||||||||
Derivative [Line Items] | |||||||||||
Major customer revenue percentage | 90.00% | 90.00% | |||||||||
Empire | Forward contracts | |||||||||||
Derivative [Line Items] | |||||||||||
Other comprehensive income, foreign currency loss | CAD 16,412,000 | CAD (17,684,000) | |||||||||
Non-regulated Energy Sales [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months | 11,612,000 | ||||||||||
Interest expense | |||||||||||
Derivative [Line Items] | |||||||||||
Unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within next twelve months | CAD 2,643,000 |
Financial instruments - Summar
Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail) | Dec. 31, 2017MMBTU |
Derivative [Line Items] | |
Commodity volumes, Gas | 15,457,678 |
Swap | |
Derivative [Line Items] | |
Commodity volumes, Gas | 2,518,812 |
Options | |
Derivative [Line Items] | |
Commodity volumes, Gas | 518,866 |
Forward contracts | |
Derivative [Line Items] | |
Commodity volumes, Gas | 12,420,000 |
Financial instruments - Impact
Financial instruments - Impact of Change in Fair Value of Natural Gas Derivative Contracts (Detail) CAD in Thousands, $ in Thousands | Dec. 31, 2017CAD | Dec. 31, 2017USD ($) | Dec. 31, 2016CAD | Dec. 31, 2016USD ($) |
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | CAD | CAD 551,134 | CAD 291,964 | ||
Regulatory liabilities, natural gas derivative contracts | CAD | CAD 725,056 | CAD 182,734 | ||
Swap | ||||
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | $ 0 | $ 0 | ||
Regulatory liabilities, natural gas derivative contracts | 287 | 175 | ||
Options | ||||
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | 0 | 27 | ||
Regulatory liabilities, natural gas derivative contracts | 138 | 92 | ||
Forward contracts | ||||
Derivative [Line Items] | ||||
Regulatory assets, natural gas derivative contracts | 6,319 | 0 | ||
Regulatory liabilities, natural gas derivative contracts | $ 20,909 | $ 0 |
Financial instruments - Long-t
Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge | Dec. 31, 2017MWh$ / MWh |
PJM Western HUB | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | MWh | 688,147 |
Receive average prices (per MW-hr) | $ / MWh | 40.40 |
NI HUB | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | MWh | 2,926,922 |
Receive average prices (per MW-hr) | $ / MWh | 29.26 |
ERCOT North HUB | |
Derivative [Line Items] | |
Notional quantity (MW-hrs) | MWh | 3,330,876 |
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, 2017 | Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | ||
Effective portion of cash flow hedge, gain (loss) | CAD 8,714 | CAD 34,355 |
Amortization of cash flow hedge | (30) | (47) |
Gain reclassified from AOCI | (6,775) | (7,554) |
Change in fair value of cash flow hedges, net of tax expense of $756 and $18,109, respectively (note 25(b)(ii)) | CAD 1,909 | CAD 26,754 |
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, 2017 | Dec. 31, 2016 | |
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized gain on derivative financial instruments | CAD 1,764 | CAD (18,689) |
Total realized loss (gain) on derivative financial instruments | 16,845 | (3,289) |
Ineffective portion of derivative financial instruments accounted for as hedges | 30 | 47 |
Gain on derivative financial instruments | (2,626) | (15,849) |
Gain (loss) on derivative instruments | 14,219 | (19,138) |
Not Designated as Hedging Instrument | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized gain on derivative financial instruments | (3,536) | (20,236) |
Total realized loss (gain) on derivative financial instruments | 16,950 | (420) |
Loss (gain) on derivative financial instruments not accounted for as hedges | 13,414 | (20,656) |
Not Designated as Hedging Instrument | Interest rate swaps | ||
Fair Value of Financial Instruments [Line Items] | ||
Total realized loss (gain) on derivative financial instruments | (193) | 0 |
Not Designated as Hedging Instrument | Energy derivative contracts | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized gain on derivative financial instruments | (52) | (426) |
Total realized loss (gain) on derivative financial instruments | 730 | 951 |
Not Designated as Hedging Instrument | Foreign exchange forward | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized gain on derivative financial instruments | 432 | (19,810) |
Total realized loss (gain) on derivative financial instruments | 16,413 | (1,371) |
Not Designated as Hedging Instrument | Commodity contracts | ||
Fair Value of Financial Instruments [Line Items] | ||
Total change in unrealized gain on derivative financial instruments | (3,916) | 0 |
Designated as Hedging Instrument | ||
Fair Value of Financial Instruments [Line Items] | ||
Ineffective portion of derivative financial instruments accounted for as hedges | CAD 805 | CAD 1,518 |
Financial instruments - Maximu
Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail) - Dec. 31, 2017 CAD in Thousands, $ in Thousands | CAD | USD ($) |
Fair Value Disclosures [Abstract] | ||
Cash and cash equivalents and restricted cash | CAD 26,259 | $ 38,491 |
Accounts receivable | 14,468 | 238,637 |
Allowance for doubtful accounts | 0 | (5,555) |
Notes receivable | 37,710 | 3,318 |
Maximum exposure to credit risk for financial instruments | CAD 78,437 | $ 274,891 |
Financial instruments - Liabil
Financial instruments - Liabilities Mature (Detail) - CAD CAD in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Long-term debt obligations | CAD 3,826,152 | |
Convertible Debentures | 1,218 | |
Advances in aid of construction | 78,636 | |
Interest on long-term debt | 2,006,130 | |
Purchase obligations | 501,867 | |
Environmental obligation | 71,873 | CAD 76,853 |
Other obligations | 155,236 | |
Total obligations | 6,727,602 | |
Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 72,023 | |
Interest rate swaps | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 10,613 | |
Foreign exchange forward | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 432 | |
Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 3,422 | |
Due less than 1 year | ||
Derivative [Line Items] | ||
Long-term debt obligations | 279,724 | |
Convertible Debentures | 0 | |
Advances in aid of construction | 1,502 | |
Interest on long-term debt | 172,659 | |
Purchase obligations | 501,867 | |
Environmental obligation | 7,765 | |
Other obligations | 44,969 | |
Total obligations | 1,026,207 | |
Due less than 1 year | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 4,386 | |
Due less than 1 year | Interest rate swaps | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 10,613 | |
Due less than 1 year | Foreign exchange forward | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 432 | |
Due less than 1 year | Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 2,290 | |
Due 2 to 3 years | ||
Derivative [Line Items] | ||
Long-term debt obligations | 570,132 | |
Interest on long-term debt | 307,463 | |
Environmental obligation | 18,858 | |
Other obligations | 0 | |
Total obligations | 905,565 | |
Due 2 to 3 years | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 8,077 | |
Due 2 to 3 years | Interest rate swaps | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 0 | |
Due 2 to 3 years | Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 1,035 | |
Due 4 to 5 years | ||
Derivative [Line Items] | ||
Long-term debt obligations | 644,969 | |
Interest on long-term debt | 250,824 | |
Environmental obligation | 5,373 | |
Other obligations | 0 | |
Total obligations | 965,892 | |
Due 4 to 5 years | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | 64,726 | |
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 | 2,331,327 | |
Convertible Debentures | 1,218 | |
Advances in aid of construction | 77,134 | |
Interest on long-term debt | 1,275,184 | |
Environmental obligation | 39,877 | |
Other obligations | 110,267 | |
Total obligations | 3,829,938 | |
Due after 5 years | Cross currency swap | Net Investment Hedging | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | (5,166) | |
Due after 5 years | Commodity contracts for regulatory operations | ||
Derivative [Line Items] | ||
Derivative financial instruments, liabilities | CAD 97 |