Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018shares | |
Document And Entity Information [Abstract] | |
Document Type | 40-F |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2018 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | FY |
Entity Registrant Name | AltaGas Ltd. |
Entity Central Index Key | 1,695,519 |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Emerging Growth Company | false |
Entity Common Stock, Shares Outstanding | 275,224,066 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents (note 31) | $ 101.6 | $ 27.3 |
Accounts receivable, net of allowances (note 22) | 1,547.5 | 382.9 |
Inventory (note 6) | 515.9 | 201.1 |
Restricted cash holdings from customers (note 31) | 4.1 | 8.9 |
Regulatory assets (note 20) | 21 | 1.1 |
Risk management assets (note 22) | 114.1 | 38.6 |
Prepaid expenses and other current assets (notes 28 and 31) | 199.9 | 36 |
Assets held for sale (note 5) | 1,528.9 | 6 |
Total current assets | 4,033 | 701.9 |
Property, plant and equipment (note 7) | 10,929.6 | 6,689.8 |
Intangible assets (note 8) | 711.9 | 588.8 |
Goodwill (notes 9) | 4,068.2 | 817.3 |
Regulatory assets (note 20) | 663 | 328.6 |
Risk management assets (note 22) | 57.7 | 15.9 |
Deferred income taxes (note 19) | 2.8 | |
Restricted cash holdings from customers (note 31) | 6.1 | 7.5 |
Prepaid post-retirement benefits (note 28) | 342.7 | |
Long-term investments and other assets (notes 11, 22, 28 and 31) | 283.1 | 312.6 |
Investments accounted for by the equity method (note 13) | 2,392.4 | 567 |
Total assets | 23,487.7 | 10,032.2 |
Current liabilities | ||
Accounts payable and accrued liabilities (notes 17 and 22) | 1,488.2 | 415.3 |
Dividends payable (note 22) | 22 | 32 |
Short-term debt (notes 14 and 22) | 1,209.9 | 46.8 |
Current portion of long-term debt (notes 15 and 22) | 890.2 | 188.9 |
Customer deposits | 98 | 30.8 |
Regulatory liabilities (note 20) | 114.9 | 10.9 |
Risk management liabilities (note 22) | 89.3 | 57.6 |
Other current liabilities (note 22) | 18.1 | 32.6 |
Liabilities associated with assets held for sale (note 5) | 171.4 | 0.3 |
Total current liabilities | 4,102 | 815.2 |
Long-term debt (notes 15 and 22) | 8,066.9 | 3,436.5 |
Asset retirement obligations (note 16) | 500.6 | 88.3 |
Unamortized investment tax credits (note 19) | 190.1 | |
Deferred income taxes (note 19) | 957.9 | 444.2 |
Regulatory liabilities (note 20) | 1,392.8 | 268.6 |
Risk management liabilities (note 22) | 213 | 13.8 |
Other long-term liabilities (note 17,18 and 22) | 122 | 201.9 |
Future employee obligations (note 28) | 302.2 | 124.5 |
Total liabilities | 15,847.5 | 5,393 |
Shareholders' equity | ||
Common shares, no par values, unlimited shares authorized; 2018 - 275.2 million and 2017 - 175.3 million issued and outstanding (note 24) | 6,653.9 | 4,007.9 |
Preferred shares (note 24) | 1,318.8 | 1,277.7 |
Contributed surplus | 373.2 | 22.3 |
Accumulated deficit | (1,905.3) | (933.6) |
Accumulated other comprehensive income (AOCI) (note 21) | 579 | 199.1 |
Total shareholders' equity | 7,019.6 | 4,573.4 |
Non-controlling interests | 620.6 | 65.8 |
Total equity | 7,640.2 | 4,639.2 |
Total liabilities and shareholders' equity | $ 23,487.7 | $ 10,032.2 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Consolidated Balance Sheets [Abstract] | ||
Common shares, no par values | ||
Common shares, shares authorized | Unlimited | Unlimited |
Common shares issued | 275.2 | 175.3 |
Common shares outstanding | 275.2 | 175.3 |
Consolidated Statements of Inco
Consolidated Statements of Income (Loss) - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Consolidated Statements of Income (Loss) [Abstract] | ||
Revenue | $ 4,256.7 | $ 2,556.2 |
EXPENSES | ||
Cost of sales, exclusive of items shown separately | 2,455.3 | 1,357.1 |
Operating and administrative | 1,129 | 572.2 |
Accretion expenses (note 16) | 10.9 | 10.9 |
Depreciation and amortization (note 7 and 8) | 394 | 282.4 |
Provisions on assets (note 10) | 728.7 | 139.6 |
Total expenses | 4,717.9 | 2,362.2 |
Income from equity investments (note 13) | 47.9 | 31.4 |
Other income (note 26) | 0.9 | 9.6 |
Foreign exchange gains | 4.5 | 1.7 |
Interest expense | ||
Short-term debt | (14) | (3.7) |
Long-term debt | (295) | (166.6) |
Income (loss) before income taxes | (716.9) | 66.4 |
Income tax expense (recovery) (note 19) | ||
Current | 24.4 | 30.5 |
Deferred | (287.6) | (64) |
Net income (loss) after taxes | (453.7) | 99.9 |
Net income (loss) applicable to non-controlling interests | (18.6) | 8.3 |
Net income (loss) applicable to controlling interests | (435.1) | 91.6 |
Preferred share dividends | (66.6) | (61.3) |
Net income (loss) applicable to common shares | $ (501.7) | $ 30.3 |
Net income (loss) per common share (note 25) | ||
Basic | $ (2.25) | $ 0.18 |
Diluted | $ (2.25) | $ 0.18 |
Weighted average number of common shares outstanding (millions) (note 25) | ||
Basic | 222.6 | 171 |
Diluted | 222.7 | 171.3 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Consolidated Statements of Comprehensive Income (Loss) [Abstract] | ||
Net income (loss) after taxes | $ (453.7) | $ 99.9 |
Other comprehensive income (loss), net of taxes | ||
Gain (loss) on foreign currency translation | 458.5 | (183.4) |
Unrealized gain (loss) on net investment hedge (note 22) | (80.2) | 6.6 |
Actuarial losses on pension plans and post-retirement benefit (PRB) plans (note 28) | (10.8) | (1) |
Reclassification of actuarial gains and prior service costs on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28) | 0.5 | 0.7 |
Settlement of PRB plan (note 28) | 0.2 | |
Curtailment of DB and PRB plan (note 28) | 2.7 | |
Unrealized loss on available-for-sale assets | (26.9) | |
Adoption of ASU 2016-01 (note 2) | 7.1 | |
Other comprehensive income (loss) from equity investees | 2.1 | (2.2) |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | 379.9 | (206) |
Comprehensive loss attributable to controlling interests and non-controlling interests, net of taxes | (73.8) | (106.1) |
Comprehensive income (loss) attributable to: | ||
Non-controlling interests | (18.6) | 8.3 |
Controlling interests | $ (55.2) | $ (114.4) |
Consolidated Statements of Equi
Consolidated Statements of Equity - CAD ($) $ in Millions | Common Stock [Member] | Cumulative Preferred Stock [Member] | Capital In Excess Of Par Value [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Non-controlling Interests [Member] | Total |
Balance, beginning of year at Dec. 31, 2016 | $ 3,773.4 | $ 985.1 | $ 17.4 | $ (600.4) | $ 405.1 | $ 34.8 | |
Adoption of ASU No. 2016-09 | Accounting Standards Update 2016-09 [Member] | 1.1 | ||||||
Balance, beginning of year at Dec. 31, 2016 | 3,773.4 | 985.1 | 17.4 | (600.4) | 405.1 | 34.8 | |
Shares issued under DRIP | 236.3 | ||||||
Shares issued, net | 293.4 | ||||||
Deferred taxes on share issuance costs | (8.3) | (0.8) | |||||
Share options expense | 1.4 | ||||||
Exercise of share options | 6.5 | (0.5) | |||||
Forfeiture of share options | (0.1) | ||||||
Foreign currency translation gain, net of income taxes | $ (183.4) | ||||||
Net income (loss) applicable to controlling interests | 91.6 | 8.3 | 91.6 | ||||
Common share dividends | (362.4) | ||||||
Preferred share dividends | (61.3) | ||||||
Other comprehensive income (loss) | (206) | (206) | |||||
Sale of non-controlling interest (note 4 and 12) | 3 | 20 | |||||
Contributions from non-controlling interests to subsidiaries | 11 | ||||||
Distribution by subsidiaries to non-controlling interests | (8.3) | ||||||
Balance at end of year at Dec. 31, 2017 | 4,007.9 | 1,277.7 | 22.3 | (933.6) | 199.1 | 65.8 | 4,573.4 |
Adoption of ASU | Accounting Standards Update 2016-09 [Member] | (1.1) | ||||||
Total equity | 4,639.2 | ||||||
Shares issued under DRIP | 325.8 | ||||||
Shares issued, net | 2,305.6 | ||||||
Preferred shares acquired through WGL Acquisition (note 24) | 41.1 | ||||||
Deferred taxes on share issuance costs | 13.3 | ||||||
Shares issued on conversion of subscription receipts, net of issuance costs | 2,305.6 | ||||||
Share options expense | 0.9 | ||||||
Exercise of share options | 1.3 | (0.1) | |||||
Forfeiture of share options | (0.1) | ||||||
Foreign currency translation gain, net of income taxes | 458.5 | ||||||
Net income (loss) applicable to controlling interests | (435.1) | (18.6) | (435.1) | ||||
Common share dividends | (462.9) | ||||||
Preferred share dividends | (66.6) | ||||||
Other comprehensive income (loss) | 379.9 | 379.9 | |||||
Sale of non-controlling interest (note 4 and 12) | 350.2 | 498.4 | |||||
Contributions from non-controlling interests to subsidiaries | 96.3 | ||||||
Distribution by subsidiaries to non-controlling interests | (30.3) | ||||||
Acquisition of non-controlling interest through WGL Acquistion (note 3) | 9 | ||||||
Balance at end of year at Dec. 31, 2018 | $ 6,653.9 | $ 1,318.8 | $ 373.2 | $ (1,905.3) | $ 579 | $ 620.6 | 7,019.6 |
Total equity | $ 7,640.2 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Cash from operations | ||
Net income (loss) after taxes | $ (453.7) | $ 99.9 |
Items not involving cash: | ||
Depreciation and amortization (note 7 and 8) | 394 | 282.4 |
Provisions on assets (note 10) | 728.7 | 139.6 |
Accretion expenses (note 16) | 10.9 | 10.9 |
Share-based compensation (note 24) | 0.8 | 1.3 |
Deferred income tax recovery (note 19) | (287.6) | (64) |
Losses on sale of assets (note 4 and 26) | 10.6 | 2.7 |
Income from equity investments (note 13) | (47.9) | (31.4) |
Unrealized losses (gains) on risk management contracts (note 22) | (80.8) | 62.5 |
Realized loss on expiry of foreign exchange options (note 22) | 36 | |
Losses (gains) on investments (note 26) | 10.1 | (3.6) |
Amortization of deferred financing costs | 29.7 | 16.9 |
Provision of doubtful accounts | 17 | |
Net change in pension and other post retirement benefits (note 28) | (3.8) | |
Other | 3.6 | (4.1) |
Asset retirement obligations settled (note 16) | (4.2) | (4) |
Distributions from equity investments | 44.5 | 30.2 |
Changes in operating assets and liabilities (note 31) | (486.5) | 1.9 |
Net cash provided (required) by operating activities | (78.6) | 541.2 |
Investing activities | ||
Business acquisitions, net of cash acquired (note 3) | (5,931) | |
Acquisition of property, plant and equipment | (990.4) | (473) |
Acquisition of intangible assets | (38.1) | (20.3) |
Acquisition of investment in a publicly traded entity | (7) | |
Contributions to equity investments | (235.4) | (16.8) |
Loan to affiliate, net of repayment (note 30) | 30 | (12.5) |
Financing receivable | (8.7) | |
Proceeds from disposition of investments (note 11) | 76.5 | |
Proceeds from IPO of ACI (note 4) | 858.9 | |
Payment for derivative contracts | (36) | |
Proceeds from disposition of assets, net of transaction costs (note 4) | 403.8 | 70.6 |
Net cash provided (required) by investing activities | (5,834.4) | (495) |
Financing activities | ||
Net issuance (repayment) of short-term debt | 497.7 | (74.2) |
Issuance of long-term debt, net of debt issuance costs | 3,595.2 | 758.1 |
Repayment of long-term debt | (1,729.5) | (861.6) |
Net issuance of bankers' acceptances | 553.6 | |
Dividends - common shares | (472.9) | (359.6) |
Dividends - preferred shares | (66.6) | (61.3) |
Distributions to non-controlling interest | (30.3) | (8.3) |
Contributions from non-controlling interests | 96.3 | 11 |
Net proceeds from shares issued on exercise of options | 1.2 | 6 |
Net proceeds from issuance of common shares | 2,633.7 | 236.3 |
Net proceeds from issuance of preferred shares | 293.4 | |
Net proceeds from sale of non-controlling interest (notes 4 and 12) | 908.6 | 24.1 |
Other | (1.9) | |
Net cash provided (required) by financing activities | 5,987 | (38) |
Change in cash, cash equivalents and restricted cash | 74 | 8.2 |
Effect of exchange rate changes on cash, cash equivalents and restricted cash | 7.3 | 1.4 |
Net change in cash classified within assets held for sale (note 5) | (4.9) | |
Restricted cash acquired (note 31) | 81 | |
Cash, cash equivalents and restricted cash beginning of year | 43.7 | 34.1 |
Cash, cash equivalents and restricted cash end of year (note 31) | $ 201.1 | $ 43.7 |
ORGANIZATION AND OVERVIEW OF TH
ORGANIZATION AND OVERVIEW OF THE BUSINESS | 12 Months Ended |
Dec. 31, 2018 | |
ORGANIZATION AND OVERVIEW OF THE BUSINESS [Abstract] | |
ORGANIZATION AND OVERVIEW OF THE BUSINESS | 1. ORGANIZATION AND OVERVIEW OF THE BUSINESS The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc., and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, and WGL Midstream Inc.; in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGSW, Inc., WGL Energy Systems, Inc., and Blythe Energy Inc. (Blythe); and, in regards to the Utility business, Washington Gas Light Company, Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR). AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and a focus on owning and operating assets to provide clean and affordable energy to its customers. The Corporation’s long-term strategy is to grow in attractive areas across its Utility, Midstream, and Power business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s footprint in two of the most prolific gas plays – the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments: · Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.7 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States, and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services; · Midstream, which, subsequent to the sale of non-core midstream assets in Canada that closed in February 2019, transacts more than 1.5 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in northeast United States and WGL’s retail gas marketing business; and · Power, which, subsequent to the sale of non-core power assets in Canada that closed in February 2019, and the sale of the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, includes 1,105 MW of gross capacity from natural gas-fired, biomass, solar, other distributed generation and energy storage assets located in Alberta, Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). Pursuant to National Instrument 52 - 107, "Acceptable Accounting Principles and Auditing Standards" (NI 52 - 107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP. PRINCIPLES OF CONSOLIDATION These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method. Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain WGL equity method investments as well as WGL consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage. All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non - controlling interest in a subsidiary that AltaGas controls, that non - controlling interest is reflected as “non - controlling interests” in the Consolidated Financial Statements. The non - controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non - controlling interests". USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods. SIGNIFICANT ACCOUNTING POLICIES Rate - Regulated Operations SEMCO Gas, ENSTAR, Washington Gas, and Hampshire (collectively Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD) and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively. The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process. Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months. Restricted Cash Holdings from Customers Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain WGL executive and outside director retirement benefit plan obligations. As of December 31, 2018, the rabbi trust funds are invested in money market funds which are considered as cash equivalents. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets. Accounts Receivable Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. Inventory Inventory consi sts of materials, supplies, natural gas, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas. Property, Plant, and Equipment (PP&E), Depreciation and Amortization Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight - line basis over the estimated useful life of the assets, with the exception of rate regulated utilities assets, where depreciation is calculated on a straight - line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities. The U.S. utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long - term interest rate. Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators. The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 3 - 80 years Midstream assets 3 - 45 years Power generation assets 2 - 120 years Corporate assets 1 - 20 years As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month they are brought into active service. Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income. Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases. Intangible Assets Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight - line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 -19 years Electricity service agreements 2 - 60 years Software 3 - 10 years Land rights 5 - 6 4 years Franchises and consents 9 - 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 years The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years. Assets Held for Sale The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized. Business Acquisitions Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition - related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired. Provisions on Assets If facts and circumstances suggest that a long - lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized. Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statement of Income. Development Costs AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations. Investments Accounted for by the Equity Method The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period. The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period. An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income. Financial Instruments Non-Utility Operations All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held - for - trading", "held - to - maturity", or "loans and receivables". Financial liabilities are classified as "held - for - trading" or other financial liabilities. Subsequent measurement is determined by classification. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Held - for - trading instruments include non - derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under "other income". Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings. The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Transaction costs related to the acquisition of held - for - trading financial assets and liabilities are expensed as incurred. Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long - term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long - term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statement of Income. Regulated Utility Operations All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income. Weather-Related Instruments WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 22 for further discussion on weather-related instruments . Hedges As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815. Non-Utility Operations The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs. Regulated Utility Operations During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt. Asset Retirement Obligations AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations. There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates , as allowed by the regulators . These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980. Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators. Revenue Recognition AltaGas has revenue from various sources, including rate regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 23. Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non - monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date. For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI. AltaGas may designate some of its U.S. dollar denominated long - term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long - term debt are included in OCI. Share Options and Other Compensation Plans Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity. AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common shares purchased from the market. The other portion of RU’s and PSUs are valued at US$1 per unit. Upon vesting, the RUs and PSUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation's performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs. Pension Plans and Post - Retirement Benefits AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs. The cost of defined benefit pension plans and post - retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post - retirement benefit plans is 9.6 years and 14.1 years, respectively. AltaGas recognizes the overfunded or underfunded status of its pension and post - retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability. For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. Income Taxes Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities. Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties. The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future. Net Income per Share Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share - based compensation awards. The potentially dilutive impact of the share - based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change. ADOPTION OF NEW ACCOUNTING STANDARDS Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU): · ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”). AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 23 for further details. The application of ASC 606 did not have a material impact on AltaGas’ consolidated financial statements in 2018; · ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recogn |
ACQUISITION OF WGL HOLDINGS INC
ACQUISITION OF WGL HOLDINGS INC. | 12 Months Ended |
Dec. 31, 2018 | |
ACQUISITION OF WGL HOLDINGS INC. [Abstract] | |
ACQUISITION OF WGL HOLDINGS INC. | 3. ACQUISITION OF WGL HOLDINGS INC. Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL for an aggregate purchase price of approximately $9.3 billion ( US$7.1 billion), including the assumption of approximately $3.3 billion ( US$2.5 billion) of debt and $41 million ( US$31 million) of preferred shares. Under the terms of the transaction, WGL shareholders received US$88.25 per common share. The net cash consideration was approximately $6.0 billion ( US$4.6 billion). The WGL Acquisition was financed through net proceeds of approximately $2.3 billion from the sale of subscription receipts, draws on the fully committed acquisition credit facility of $3.0 billion ( US$2.3 billion) and existing cash on hand. The draws on the acquisition credit facility included additional amounts for the payment of fees and regulatory commitments related to the WGL Acquisition. The sale of the subscription receipts was completed in the first quarter of 2017 and upon closing of the WGL Acquisition, the subscription receipts were exchanged into approximately 84.5 million common shares of AltaGas. The WGL Acquisition is accounted for as a business combination using the acquisition method of accounting whereby the acquired assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed is recognized as goodwill at the acquisition date. The following table summarizes the purchase price allocation representing the consideration paid and the fair value of the net assets acquired as at July 6, 2018 using an exchange rate of 1.31 to convert U.S. dollars to Canadian dollars. The purchase price allocation is provisional and reflects Management’s current best estimate of the fair value of WGL’s assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the evaluation of fixed assets, goodwill and deferred income taxes for certain elements of the acquired business. As the additional information becomes available, the purchase price allocation may differ from the preliminary purchase price allocation below. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition. The following table summarizes the estimated fair values that were assigned to the net assets of WGL at the date of acquisition: Purchase consideration $ 5,973 Fair value assigned to net assets Current assets $ 1,187 Property, plant and equipment 5,943 Intangible assets 637 Regulatory assets 402 Long-term investments 1,411 Other long-term assets 449 Current liabilities (1,798) Long-term debt (2,548) Preferred shares (41) Regulatory liabilities (1,125) Deferred income taxes (772) Other long-term liabilities (959) Non-controlling interest (9) Fair value of net assets acquired $ 2,777 Goodwill $ 3,196 The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of WGL’s rate regulated property, plant and equipment is determined using a market participant perspective, which is equal to the carrying amount. The preliminary fair values of the remaining non-regulated property, plant and equipment is determined using both the income and cost approaches and resulted in an estimated fair value decrease relative to carrying value of approximately $92 million related to solar distributed generation assets. Long-term investments include WGL’s 55 percent equity investment in Meade Pipeline Co. LLC. (Meade), a 10 percent equity interest in Mountain Valley Pipeline LLC, and a 30 percent equity interest in Stonewall Gas Gathering Systems LLC. Meade owns 39 percent of Central Penn, and WGL owns a 21 percent indirect net interest in Central Penn. The preliminary fair value of these investments has been determined using an income approach, resulting in an estimated fair value increase of approximately $464 million. Intangible assets consist of customer relationships, contracts relating to gas transportation capacity, and natural gas purchase and sale agreements for energy exports. The preliminary fair value of these assets is determined using an income approach, resulting in an estimated fair value of approximately $637 million. The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature. The fair value of long-term debt was estimated based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer, WGL or Washington Gas Light Company. This resulted in a fair value increase of approximately $87 million, with a corresponding regulatory offset. Deferred income tax assets and liabilities have been applied on the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities. The preliminary purchase price allocation includes goodwill of approximately $3.2 billion. The goodwill is primarily related to the investment in low risk, long-life rate regulated assets, opportunities to grow the gas midstream business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill. Pre-tax acquisition expenses and merger commitment costs for the year ended December 31, 2018 of approximately $237.2 million were incurred and included in the Consolidated Statements of Income (2017 – $65.7 million). Upon completion of the WGL Acquisition, AltaGas began consolidating WGL. Since the closing date through December 31, 2018, WGL has generated approximately $1,406 million in revenues and $113 million in net loss after tax. The loss was primarily due to the payment of various regulatory commitments as well as seasonality in certain of WGL’s operating businesses. The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2018 and 2017 gives effect to the WGL Acquisition as if it had closed on January 1, 2017. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the WGL Acquisition taken place at the beginning of 2017, nor is it indicative of the results that may be expected in future periods. Year ended December 31 2018 2017 Pro forma revenue $ 5,962 $ 5,704 Pro forma net income (loss) after taxes $ (304) $ 450 Pro forma revenue excludes the gains and losses on foreign exchange contracts, as these contracts were used to mitigate the foreign exchange risks associated with the cash purchase price of WGL. As such, the gains and losses on these foreign exchange contracts are directly incremental to the WGL Acquisition and are non-recurring in nature. These adjustments increased pro forma revenue by $2 million for the year ended December 31, 2018, and increased pro forma revenue by $34 million for the year ended December 31, 2017. Pro forma net income (loss) after taxes excludes all non-recurring acquisition-related expenses and merger commitment costs incurred by AltaGas and WGL and AltaGas’ realized and unrealized gains and losses on foreign exchange contracts entered into to mitigate the foreign exchange risk associated with the WGL Acquisition. Pro forma net income (loss) after taxes was also adjusted to exclude financing costs associated with the bridge facility for the WGL Acquisition, and amortization of fair value adjustments relating to property, plant and equipment, intangible assets, and other long-term investments as well as tax impacts of all the previously noted adjustments. For the year ended December 31, 2018, the total after-tax pro forma adjustments increased net income (loss) after taxes by $132 million (2017 – $19 million ). |
SALE OF MINORITY INTEREST AND O
SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS | 12 Months Ended |
Dec. 31, 2018 | |
Sale of Minority Interest and Other Dispositions [Member] | |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |
SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS AND ASSETS HELD FOR SALE | 4. SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS Northwest Hydro Facilities On June 22, 2018, AltaGas completed the disposition of a 35 percent indirect equity interest in the Northwest Hydro facilities for gross cash proceeds of approximately $921.6 million. The disposition was completed through the sale of 35 percent of Northwest Hydro Limited Partnership (NW Hydro LP), a subsidiary of AltaGas which indirectly holds the Northwest Hydro facilities. At December 31, 2018, AltaGas continues to consolidate NW Hydro LP ( Note 12 ). Upon close of the sale, AltaGas recognized a non-controlling interest of $420.4 million, a deferred income tax liability of $153.3 million and contributed surplus of $3 35.2 million on the Consolidated Balance Sheets, net of transaction costs. There was no impact to the Consolidated Statements of Income upon closing of this transaction. On December 13, 2018, AltaGas announced that it reached an agreement for the sale of its remaining interest of approximately 55 percent in the Northwest Hydro facilities. The sale was completed in January 2019 (Note s 5 and 33). Initial Public Offering of AltaGas Canada Inc. On October 25, 2018, the initial public offering (IPO) of AltaGas Canada Inc. (ACI) was successfully compl eted, reflecting a final price of $14.50 per common share of ACI. The over-allotment option was exercised in full, and as a result , AltaGas holds approximately 37 percent of ACI common shares at December 31, 2018. Net proceeds to AltaGas (consisting of cash and debt) to AltaGas after the deduction of underwriting fees and expenses were approximately $892.2 million. ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities. In addition to a pre-tax provision of $193.7 million, AltaGas recognized a pre-tax loss on disposition of $0.5 million in the Consolidated Statement of Income under the line item “other income ” for the year ended December 31, 2018. Non-Core San Joaquin Power Assets in California On November 13, 2018, AltaGas completed the disposition of the San Joaquin facilities for a sale price of approximately US$299.4 million. The assets comprise the Tracy, Hanford and Henrietta plants totaling 523 MW of capacity. In addition to a pre-tax provision of $340.6 million, AltaGas recognized a pre-tax loss on disposition of $14.4 million in the Consolidated Statements of Income under the line item “other income ” for the year ended December 31, 2018. Other U.S. Power Assets On December 11, 2018, AltaGas completed the disposition of Busch Ranch, a wind asset in the United States , for a sale price of approximately US$16.3 million. AltaGas recognized a pre-tax gain on disposition of $3.2 million in the Consolidated Statements of Income under the line item “other income ” for the year ended December 31, 2018. Other Dispositions In March 2018, AltaGas completed the disposition of the Acme and Shaunavon gas processing facilities in the Midstream segment for gross proceeds of approximately $7.0 million. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $1.3 million in the Consolidated Statements of Income under the line item “other income” for the year ended December 31, 2018. In March 2017, AltaGas completed the disposition of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets in the Midstream segment to Nova Chemicals Corporation for gross proceeds of approximately $67.0 million. AltaGas recognized a pre-tax loss on disposition of approximately $3.4 million in the Consolidated Statement of Income under the line item “other income” for the year ended December 31, 2017 related to this disposition. |
ASSETS HELD FOR SALE
ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2018 | |
Assets Held for Sale [Member] | |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |
SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS AND ASSETS HELD FOR SALE | 5. ASSETS HELD FOR SALE As at December 31, 2018 December 31, 2017 Assets held for sale Cash $ 4.9 $ — Accounts receivable 85.2 0.3 Inventory 0.5 — Property, plant and equipment 1,189.6 5.3 Intangible assets 248.7 0.1 Goodwill — 0.3 $ 1,528.9 $ 6.0 Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ 23.8 $ — Asset retirement obligations 10.8 0.3 Other long-term liabilities 136.8 — $ 171.4 $ 0.3 Non-Core Midstream and Power Assets in Canada In the third quarter of 2018, AltaGas entered into definitive agreements for the sale of selected non-core smaller scale gas midstream and power assets in Canada, as well as AltaGas’ commercial and industrial customer portfolio in Canada, for an aggregate purchase price of approximately $165.0 million. The transaction is subject to customary closing conditions and approvals, and was completed in February 2019. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassi fication of assets totaling $102.1 million to assets held for sale and liabilities totaling $10.8 million to liabilities associated with assets held for sale on the Consolidated Balance Sheets . P re-tax provisions of $121.4 million on property, plant and equipment, $0.5 million on intangible assets, and $5.1 million on goodwill were recognized in 2018 due to the reduction of the carrying value of the assets to fair value less costs to sell. These assets are recorded in the Midstream and Power segments. The transaction also includes the 43.7 million shares of Tidewater Midstream and Infrastructure Inc. previously held by AltaGas. This portion of the transaction was completed in September 2018 (Note 11). Northwest Hydro Facilities On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities for proceeds of approximately $1.37 billion. The transaction was completed in January 2019. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of $1,350.2 million of assets to assets held for sale and $160.6 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets . These assets are recorded in the Power segment. Included within liabilities associated with assets held for sale is the Northwest Hydro NTL liability. In 2010, AltaGas entered into a 60 - year CPI-indexed Electricity Purchase Agreement (EPA) and other related agreements with BC Hydro for the 195-MW Forrest Kerr run - of - river hydroelectric facility. As part of the related agreements, AltaGas agreed to pay BC Hydro annual payments of approximately $11.0 million per year, adjusted for inflation, in support of the construction and operation of the Northwest Transmission Line (NTL) until 2034. With the agreement for the sale of AltaGas’ remaining indirect equity interest in the Northwest Hydro facilities, this liability has been reclassified to liabilities associated with assets held for sale. Architect of the Capitol (AOC) Project In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable related to the construction of an energy management services project . The transaction is subject to customary closing conditions, and is expected to be completed in the first quarter of 2019. Accordingly, the carrying value of the asset was classified as held for sale, which resulted in the reclassification of $76.6 million of accounts receivable to assets held for sale on the Consolidated Balance Sheets . A pre-tax provision of $6.0 million was recognized in 2018 due to the reduction of the carrying value of the receivable to fair value less costs to sell. This asset is recorded in the Power segment. |
INVENTORY
INVENTORY | 12 Months Ended |
Dec. 31, 2018 | |
INVENTORY [Abstract] | |
INVENTORY | 6. INVENTORY December 31, December 31, As at 2018 2017 Natural gas held in storage $ 418.0 $ 133.9 Materials and supplies 53.3 32.3 Renewable energy credits and emission compliance instruments 38.2 28.4 Other inventory 6.4 6.5 $ 515.9 $ 201.1 |
PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2018 | |
PROPERTY, PLANT AND EQUIPMENT [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | 7. PROPERTY, PLANT AND EQUIPMENT As at December 31, 2018 December 31, 2017 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 7,090.5 $ (89.7) $ 7,000.8 $ 2,245.4 $ (226.1) 2,019.3 Midstream 3,178.2 (845.7) 2,332.5 2,801.4 (636.3) $ 2,165.1 Power 4,633.9 (1,858.3) 2,775.6 2,874.8 (392.3) 2,482.5 Corporate 49.4 (39.1) 10.3 65.9 (37.7) 28.2 Reclassified to assets held for sale (note 5) (2,999.3) 1,809.7 (1,189.6) (16.7) 11.4 (5.3) $ 11,952.7 $ (1,023.1) $ 10,929.6 $ 7,970.8 $ (1,281.0) $ 6,689.8 Interest capitalized on long-term capital construction projects for the year ended December 31, 2018 was $12.6 million ( 2017 - $10.8 million). As at December 31, 201 8, the Corporation had approximately $872. 7 million ( December 31, 2017 - $269.5 million) of capital projects under construction that were not yet subject to amortization. Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2018 was $324 . 3 million ( 2017 - $239.7 million). |
INTANGIBLE ASSETS
INTANGIBLE ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
INTANGIBLE ASSETS | 8. INTANGIBLE ASSETS As at December 31, 2018 December 31, 2017 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value E&T contracts $ 26.6 $ (14.3) $ 12.3 $ 26.6 $ (13.4) $ 13.2 Electricity service agreements 269.5 (25.9) 243.6 603.1 (108.5) 494.6 Energy services relationships 176.1 (33.8) 142.3 10.2 (8.1) 2.1 Software 293.9 (77.7) 216.2 126.8 (61.6) 65.2 Land rights 1.4 (0.2) 1.2 11.0 (2.4) 8.6 Commodity contracts 346.3 (6.3) 340.0 — — — Franchises and consents 5.0 — 5.0 7.4 (2.2) 5.2 Reclassified to assets held for sale (note 5) (277.4) 28.7 (248.7) (0.1) — (0.1) $ 841.4 $ (129.5) $ 711.9 $ 785.0 $ (196.2) $ 588.8 Amortization expense related to intangible assets for the year ended December 31, 2018 was $69.7 million ( 2017 - $42.7 million). As at December 31, 2018 , the Corporation excluded $ 196.4 million ( December 31, 2017 - $11.2 million) from the asset base subject to amortization. Items excluded related to gas transportation capacity contracts, software assets under development, and assets with an indefinite life. The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31: 2019 $ 84.2 2020 $ 82.5 2021 $ 57.6 2022 $ 132.3 2023 $ 38.3 Thereafter $ 120.6 |
GOODWILL
GOODWILL | 12 Months Ended |
Dec. 31, 2018 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
GOODWILL | 9. GOODWILL December 31, December 31, As at 2018 2017 Balance, beginning of year $ 817.3 $ 856.0 Provisions on assets (notes 5 and 10) (124.2) — Business acquisition (note 3) 3,196.4 — Foreign exchange translation 178.7 (38.4) Reclassified to assets held for sale — (0.3) Balance, end of year $ 4,068.2 $ 817.3 |
PROVISIONS ON ASSETS
PROVISIONS ON ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
PROVISIONS ON ASSETS | 10. PROVISIONS ON ASSETS Year ended December 31 2018 2017 Utilities $ 193.7 $ — Midstream 153.7 6.6 Power 381.3 133.0 $ 728.7 $ 139.6 Utilities In 2018, AltaGas recor ded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distribution utility assets that were classified as held for sale in the third quarter of 2018. The pre-tax provision was comprised of $119.1 million on goodwill and $74.6 million on property, plant and equipment. No provisions on assets were recorded in 2017 for the Utilities segment. Midstream In 2018, AltaGas recorded pre-tax provisions totaling $153.7 million in the Midstream segment. The pre-tax provision s included $117.2 million related to certain non-core midstream assets that are classified as held for sale at December 31, 2018 ( Note 5) and $36.5 million related to shut-in assets in the South, Cold Lake and Northwest operating areas. The total pre-t ax provisions of $153.7 million were comprised of $148.1 million on property, plant, and equipment, $0.5 million on intangible assets, and $5.1 million on goodwill. In 2017, AltaGas recorded a pre-tax provision on assets of $6.6 million on a non-core gas processing facility that was classified as held for sale ( Note 5). Power In 2018, AltaGas recorded pre-tax provisions totaling $381.3 million in the Power segment. Of this, $340.6 million related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were disposed of in November 2018. The pre-tax provision on the California power assets was comprised of $221.3 million on property, plant, and equipment and $119.3 million on i ntangible assets. In addition, pre-tax provision s of $9.8 million were recorded on certain non-core power assets in Canada that are classified as held for sale at December 31, 2018 ( Note 5) , $23.1 million on a development project in the U.S., $1.8 million on the Pomona natural gas-fired co-generation facility in the United States , and $6.0 million on a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018 (Note 5) . In 2017, AltaGas recognized pre-tax provisions on assets related to the Hanford and Henrietta gas-fired peaking plants in California, certain non-core development stage gas-fired peaking projects in California, and the Kent development project in Alberta of $133.0 million. The pre-tax provisions of $133.0 million were comprised of $48.5 million on intangible assets and $84.5 million on property, plant and equipment. |
LONG-TERM INVESTMENTS AND OTHER
LONG-TERM INVESTMENTS AND OTHER ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
LONG-TERM INVESTMENTS AND OTHER ASSETS [Abstract] | |
LONG-TERM INVESTMENTS AND OTHER ASSETS | 11. LONG-TERM INVESTMENTS AND OTHER ASSETS As at December 31, 2018 December 31, 2017 Investments in publicly-traded entities $ 8.4 $ 95.0 Loan to affiliate (note 30) 45.0 75.0 Deferred lease receivable 24.4 29.0 Debt issuance costs associated with credit facilities 7.9 20.3 Refundable deposits 16.2 14.9 Prepayment on long-term service agreements 82.5 68.1 Subscription receipts issuance costs — 1.7 Contract asset (note 23) 11.5 — Rabbi trust (note 28) 61.7 — Other 25.5 8.6 $ 283.1 $ 312.6 In 2018, as part of the agreement for the sale of non-core midstream and power assets in Canada, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. for gross proceeds of $63.4 million. For the year ended December 31, 2018, a realized loss of $2.0 million was recognized in the Consolidated Statements of Income under the line item “other income ” in relation to the sale of these shares. |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 12 Months Ended |
Dec. 31, 2018 | |
VARIABLE INTEREST ENTITIES [Abstract] | |
VARIABLE INTEREST ENTITIES | 12. VARIABLE INTEREST ENTITIES Consolidated VIEs AltaGas consolidates VIEs where the Corporation is deemed the primary beneficiary. The primary beneficiary of a VIE has the power to direct the activities of the entity that most significantly impact its economic performance such as being the provider of construction, operating and marketing services to the entity. In addition, the primary beneficiary of a VIE also has the obligation to absorb losses of the entity or the right to receive benefits that could potentially be significant to the VIE. AltaGas determined that it is the primary beneficiary of the following VIEs: Northwest Hydro Limited Partnership On May 4, 2018, NW Hydro LP was formed to indirectly hold the assets of the Northwest Hydro facilities. On June 22, 2018, AltaGas closed the sale of a 35 percent indirect equity interest in its Northwest Hydro facilities through the sale of 35 percent of NW Hydro LP, and its general partner, Northwest Hydro GP Inc. (NW Hydro GP). AltaGas has determined that NW Hydro LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the continued provision of all operational, maintenance and management functions for the Northwest Hydro facilities. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to the Northwest Hydro facilities. As such, AltaGas has consolidated NW Hydro LP and has recorded $420.4 million of the $921.6 million proceeds received as a non-controlling interest with the remainder of the proceeds, less deferred tax and transaction costs, recognized as contributed surplus in the amount of $334.6 million. On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities (including NW Hydro LP) for proceeds of approximately $1.37 billion. The transaction was subject to customary closing conditions and approvals, and closed in January 2019 . The assets and liabilities of NW Hydro LP have been classified as held for sale at December 31, 2018 (Note 5). The assets of NW Hydro LP are the property of NW Hydro LP and are not available to AltaGas for any other purpose. NW Hydro LP’s asset balances can only be used to settle its own obligations. The liabilities of NW Hydro LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. Ridley Island LPG Export Limited Partnership On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET, which is estimated to be $450 to $500 million, will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP . AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP . In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP and recorded $20.0 million of the $24.1 million proceeds received from Vopak on formation of RILE LP as a non-controlling interest with the remainder of the proceeds less deferred tax recognized as contributed surplus in the amount of $3.0 million. The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. Upon commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET operating costs by AltaGas LPG in accordance with the terms set out in the agreement. Variable Interest Entities Acquired in WGL Acquisition In connection with the WGL Acquisition (Note 3), AltaGas has acquired both consolidated and unconsolidated VIEs: Consolidated VIE Investments At December 31 , 2018, WGSW Inc. (WGSW) was the primary beneficiary of SFGF LLC (SFGF), SFRC, LLC (SFRC), SFGF II, LLC (SFGF II), SFEE LLC (SFEE), and ASD Solar LP (ASD), because of its ability to direct the activities most significant to the economic performance of those entities plus the right to receive potentially significant benefits or the obligation to absorb potentially significant losses. Accordingly, these VIEs have been consolidated: SFGF, SFRC, and SFGF II WGSW, along with its various tax equity partners, formed the tax equity partnerships SFGF, SFRC, and SFGF II to acquire, own, and operate distributed generation solar projects nationwide. WGSW is the managing member of these investments and will provide cash equal to the purchase price of the solar projects less any contributions from the tax-equity partner for projects sold into the partnerships. WGL Energy Systems is the developer of the projects and sells them to the partnerships, and is the operations and maintenance provider. P rofits and l osses are allocated between the partners under the HLBV method of accounting and the portion allocated to the tax equity partner is included in “net income (loss) attributable to non-controlling interest” on the accompanying Consolidated Statements of Income and is recorded to non-controlling interest on the accompanying Consolidated Balance Sheets. SFEE In 2016, WGSW and a tax equity partner formed SFEE to acquire distributed generation solar projects that were to be developed and sold by a third-party developer or WGL Energy Systems. New projects were to be designed and constructed under long-term power purchase agreements. SFEE is considered a VIE and is consolidated by WGSW. ASD WGSW is a limited partner in ASD, a limited partnership formed to own and operate a portfolio of residential solar projects, primarily rooftop photovoltaic power generation systems. SF ASD, a wholly-owned subsidiary of WGL Energy Systems, has management rights and control of ASD. The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs: As at December 31, December 31, 2018 2017 Current assets $ 1,383.5 $ 1.4 Property, plant and equipment 619.2 84.3 Long-term investments and other assets 48.0 48.0 Current liabilities (161.8) — Asset retirement obligations (0.9) — Deferred tax credits (3.0) — Net assets $ 1,885.0 $ 133.7 Unconsolidated VIE Investments Meade Pipeline Co. LLC (Meade) In 2014, WGL Midstream and certain partners entered into a limited liability company agreement and formed Meade, a Delaware limited liability company, to develop and own, jointly with Transcontinental Gas Pipe Line Company, LLC, a regulated pipeline, Central Penn Pipeline (Central Penn), a segment of the larger Atlantic Sunrise project. Central Penn is an approximately 185 -mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania with the capacity to transport and deliver up to approximately 1.7 Bcf per day of natural gas. As at December 31, 2018, AltaGas held a n equity investment in Meade with a carrying value of $666.9 million , inclusive of fair value adjustments on acquisition date ( Note 3) . WGL Midstream owns a 55 percent interest in Meade ( 21 percent indirect interest in Central Penn) and on a cash basis, as of December 31, 2018, WGL Midstream has spent approximately US$446 million as its share of the construction costs. Although WGL Midstream holds greater than a 50 percent interest in Meade, Meade is not consolidated by WGL Midstream and instead is accounted for under the equity method of accounting. WGL Midstream is not the primary beneficiary of Meade as it does not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applies the HLBV equity method of accounting and any profits and losses are included in “income from equity investments” in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance. The maximum financial exposure to loss as a result of the involvement with this VIE is equal to WGL Midstream's capital contributions. |
INVESTMENTS ACCOUNTED FOR BY EQ
INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD | 12 Months Ended |
Dec. 31, 2018 | |
INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD [Abstract] | |
INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD | 13. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD Carrying value as at December 31 Equity income (loss) for the year ended December 31 Description Location Ownership Percentage 2018 2017 2018 2017 AltaGas Canada Inc. (ACI) Canada 36.75 $ 112.5 $ — $ 5.4 $ — AltaGas Idemitsu Joint Venture LP (AIJVLP) Canada 50 342.9 323.3 2.1 6.6 Constitution Pipeline, LLC (Constitution) United States 10 — — (0.2) — Craven County Wood Energy LP United States 50 7.8 20.9 (14.1) 3.3 Eaton Rapids Gas Storage System United States 50 29.4 26.4 2.0 2.5 Grayling Generating Station LP United States 50 29.0 27.6 3.6 3.5 Inuvik Gas Ltd. (a) Canada 33.333 — — (0.2) — Meade Pipeline Co. LLC (Meade) (b) United States 55 757.8 — 12.2 — Mountain Valley Pipeline, LLC (Mountain Valley) United States 10 532.5 — 11.5 — Sarnia Airport Storage Pool LP Canada 50 18.7 18.8 1.0 1.0 Petrogas Preferred Shares Canada n/a 150.0 150.0 12.8 12.8 Tidewater Midstream and Infrastructure Ltd. (c) Canada n/a — — — 1.7 Stonewall Gas Gathering Systems LLC United States 30 411.8 — 11.8 — $ 2,392.4 $ 567.0 $ 47.9 $ 31.4 (a) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018. (b) Meade is a VIE (Note 12). (c) AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. in September 2018 (Note 11). Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows: Year ended December 31 2018 2017 Revenues $ 351.6 $ 110.6 Expenses (142.7) (74.2) $ 208.9 $ 36.4 As at December 31 2018 2017 Current assets $ 1,204.6 $ 24.8 Property, plant and equipment $ 7,602.5 $ 82.8 Intangible assets $ 22.9 $ 5.6 Long-term investments and other assets $ 1,326.6 $ 843.3 Current liabilities $ (1,015.2) $ (41.7) Other long-term liabilities $ (949.6) $ (189.1) Petrogas Preferred Shares AltaGas, indirectly through its investment in AIJVLP, holds a one-third equity interest in Petrogas. In 2016, AltaGas directly invested $150.0 million to subscribe for 6,000,000 cumulative redeemable convertible preferred shares of Petrogas. These preferred shares form part of AltaGas’ overall investment in Petrogas and entitle AltaGas to a fixed, cumulative, preferential cash dividend at a rate of 8.5 percent per annum payable quarterly. These preferred shares are, in the normal course, redeemable at any time on or after January 1, 2018 and convertible into a specified number of common shares at the option of either holder at any time on or after April 19, 2018. For the year ended December 31, 2018 , AltaGas received dividend income of $ 12.8 million ( 2017 - $12.8 million) from the Petrogas preferred shares, which has been included in the Consolidated Statement of Income under the line item “income from equity investments”. AltaGas Canada Inc. As at December 31, 2018, AltaGas owns an approximate 37 percent equity interest in ACI. On October 25, 2018, the ACI IPO was successfully completed reflecting a final price of $14.50 per common share of ACI (Note 4). ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent interest in the Northwest Hydro facilities. Equity Method Investments Acquired in WGL Acquisition In connection with the WGL Acquisition (Note 3), AltaGas acquired the following investments accounted for by the equity method that are not considered VIEs: Mountain Valley Pipeline, LLC (Mountain Valley) WGL Midstream owns a 10 percent equity interest in Mountain Valley Pipeline, LLC. The proposed pipeline, which will be operated by EQM Gathering Opco, LLC (EQM) and developed, constructed, and owned by Mountain Valley (a venture of EQT Midstream Partners LP (EQT) and other entities), will transport approximately 2.0 Bcf of natural gas per day and will extend from Equitrans, LP’s system in Wetzel County, West Virginia to Transcontinental Gas Pipe Line Company LLC's Station 165 in Pittsylvania County, Virginia. The pipeline is expected to span approximately 300 miles. At December 31, 2018, AltaGas held a n equity investment in Mountain Valley with a carrying value of $532.5 million, inclusive of fair value adjus tments on acquisition date ( Note 3) . WGL Midstream expects to invest approximately US $350 million in scheduled capital contributions through the in-service date of the pipeline based on its contracted share of project costs. The equity method is considered appropriate because Mountain Valley is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent resulting in WGL Midstream maintaining a more than minor influence over the partnership operating and financing policies. Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance. In April 2018, WGL Midstream entered into a separate agreement with EQ M to acquire a 5 percent equity interest in a project to build a lateral interstate natural gas pipeline connecting to the Mountain Valley Pipeline . Stonewall Gas Gathering System (Stonewall) WGL Midstream has a 30 percent equity interest in an entity that owns and operates certain assets known as the Stonewall Gas Gathering System. Stonewall has the capacity to gather up to 1.4 Bcf of natural gas per day from the Marcellus production region in West Virginia, and connects with an interstate pipeline system that serves markets in the mid-Atlantic region. As at December 31, 2018, the carrying value of the equity investment in Stonewall was $4 11.8 million , inclusive of fair value adjus tments on acquisition date ( Note 3). Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income. Constitution Pipeline Company, LLC (Constitution) WGL Midstream has an investment in Constitution, owning a 10 percent equity interest in the proposed pipeline venture. At December 31, 2018, the carrying value of the equity investment in Constitution was $nil, reflecting AltaGas’ fair value on acquisition date ( Note 3). This natural gas pipeline venture is proposed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets. In addition to the above non-VIE equity investments acquired in the WGL Acquisition, the Company’s investment in Meade (Note 12) is also accounted for using the equity method. Provisions on investments accounted for by the equity method During the year ended December 31, 2018, AltaGas recorded a pre-tax provision of $14.5 million against AltaGas’ investment in Craven Wood County Energy LP. No provisions were recorded for the year ended December 31, 2017. |
SHORT-TERM DEBT
SHORT-TERM DEBT | 12 Months Ended |
Dec. 31, 2018 | |
SHORT-TERM AND LONG-TERM DEBT [Abstract] | |
SHORT-TERM DEBT | 14. SHORT-TERM DEBT As at December 31, 2018 December 31, 2017 Bank indebtedness (a) $ 0.2 $ 6.2 US$150 million operating facility (b) — 31.7 $25 million operating facility (c) — 8.9 Commercial paper (d) 1,145.2 — Project financing 64.5 — $ 1,209.9 $ 46.8 (a) Bank indebtedness bears interest at the lender's prime rate or at the interest rate applicable to bankers' acceptances. The prime lending rate at December 31, 2018 was 3.95 percent ( December 31, 2017 – 3.2 percent). (b) As at December 31, 2018 , SEMCO held a US$1 50 million ( December 31, 2017 - US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 20, 202 3 . Draws on the facility can be by way of U.S. base - rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2018 were $0.7 million ( December 31, 2017 - $0.6 million). (c) Upon completion of the ACI IPO , the operating facility was transferred to ACI. (d) WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position . Other Credit Facilities As at December 31, 2018 , the Corporation held a $70.0 million ( December 31, 2017 - $50.0 million) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender's prime rate or at the bankers' acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2018 were $nil ( December 31, 2017 - $nil ). As at December 31, 2018 , AltaGas held a $150.0 million ( December 31, 2017 - $150.0 million) unsecured four - year extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base - rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Letters of credit outstanding under this facility as at December 31, 2018 were $117.0 million ( December 31, 2017 - $40.8 million). As at December 31, 2018 , AltaGas held a US$200.0 million ( December 31, 2017 - $150.0 million) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2018 were $147.3 million ( December 31, 2017 - $71.3 million). As at December 31, 2018, AltaGas held a $ 35 .0 million (December 31, 2017 - $nil ) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender’s prime rate or at the bankers’ acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2018 were $6 . 0 million (December 31, 2017 - $nil ). As at December 31, 2018, AltaGas held a US$300 .0 million (December 31, 2017 - $nil ) unsecured extendible revolving letter of credit facility. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding on this facility as at December 31, 2018 were $nil (December 31, 2017 - $nil ). Credit Facilities Acquired in WGL Acquisition As at December 31, 2018, WGL held a US$650.0 million unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base - rate loans, LIBOR loans, bankers’ acceptances or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2018. As at December 31, 2018, Washington Gas held a US$350.0 million (December 31, 2017 - $nil ) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base - rate loans, LIBOR loans, bankers’ acceptances or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2018 . WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. At December 31, 2018, commercial paper outstanding totaled US$8 39.5 million for WGL and Washington Gas. Project Financing Washington Gas previously obtained third-party project financing on behalf of the United States federal government to provide funds during the construction of certain energy management services projects entered into under Washington Gas' area-wide contract. When these projects are formally accepted by the government and deemed complete, Washington Gas assigns the ownership of the receivable to the third-party lender in satisfacti on of the obligation, removing both the receivable and the obligation related to the financin g from the Consolidated Financial Statements. At December 31, 2018, draws related to project financing were $64.5 million (December 31, 2017 - $nil ) . |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2018 | |
SHORT-TERM AND LONG-TERM DEBT [Abstract] | |
LONG-TERM DEBT | 15. LONG-TERM DEBT December 31, December 31, As at Maturity date 2018 2017 Credit facilities $1,400 million unsecured extendible revolving (a) 15-May-2023 $ 964.7 $ 219.1 US$300 million unsecured extendible revolving (b) 15-May-2022 287.8 — Acquisition credit facility 6-Jan-2020 113.2 — US $1,200 million revolving credit facility (g) 28-Dec-2021 1,637.0 — Medium-term notes (MTNs) $175 million Senior unsecured - 4.60 percent 15-Jan-2018 — 175.0 $200 million Senior unsecured - 4.55 percent 17-Jan-2019 200.0 200.0 $200 million Senior unsecured - 4.07 percent 1-Jun-2020 200.0 200.0 $350 million Senior unsecured - 3.72 percent 28-Sep-2021 350.0 350.0 $300 million Senior unsecured - 3.57 percent 12-Jun-2023 300.0 300.0 $200 million Senior unsecured - 4.40 percent 15-Mar-2024 200.0 200.0 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 299.9 299.9 $100 million Senior unsecured - 5.16 percent 13-Jan-2044 100.0 100.0 $300 million Senior unsecured - 4.50 percent 15-Aug-2044 299.8 299.8 $350 million Senior unsecured - 4.12 percent 7-Apr-2026 349.8 349.8 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 199.9 199.9 $250 million Senior unsecured - 4.99 percent 4-Oct-2047 250.0 250.0 WGL and Washington Gas medium-term notes US $500 million Senior unsecured - 2.25 to 4.76 percent Jan - Nov 2019 682.1 — US $250 million Senior unsecured - 2.88 percent 12-Mar-2020 341.1 — US $20 million Senior unsecured - 6.65 percent 20-Mar-2023 27.3 — US $40.5 million Senior unsecured - 5.44 percent 11-Aug-2025 55.3 — US $53 million Senior unsecured - 6.62 to 6.82 percent Oct - 2026 72.3 — US $72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 98.2 — US $52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 70.9 — US $8.5 million Senior unsecured - 7.50 percent 1-Apr-2030 11.6 — US $50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 68.2 — US $75 million Senior unsecured - 5.21 percent 3-Dec-2040 102.3 — US $75 million Senior unsecured - 5.00 percent 15-Dec-2043 102.3 — US $300 million Senior unsecured - 4.22 to 4.60 percent Sep - Dec 2044 409.3 — US $450 million Senior unsecured - 3.80 percent 15-Sep-2046 613.9 — SEMCO long-term debt US$300 million SEMCO Senior secured - 5.15 percent (d) 21-Apr-2020 409.3 376.4 US$82 million CINGSA Senior secured - 4.48 percent (e) 2-Mar-2032 86.3 85.2 Debenture notes PNG 2018 Series Debenture - 8.75 percent (c)(f) 15-Nov-2018 — 7.0 PNG 2025 Series Debenture - 9.30 percent (c)(f) 18-Jul-2025 — 13.0 PNG 2027 Series Debenture - 6.90 percent (c)(f) 2-Dec-2027 — 14.0 CINGSA capital lease - 3.50 percent 1-May-2040 0.6 0.5 CINGSA capital lease - 4.48 percent 4-Jun-2068 0.2 0.2 Fair value adjustment on WGL Acquisition (note 3) 89.0 — $ 8,992.3 $ 3,639.8 Less debt issuance costs (35.2) (14.4) 8,957.1 3,625.4 Less current portion (890.2) (188.9) $ 8,066.9 $ 3,436.5 (a) Borrowings on the facility can be by way of prime loans, U.S. base - rate loans, LIBOR loans, bankers' acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made. (b) Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, LIBOR loans , or letters of credit. (c) Collateral for the Secured Debentures and secured extendible revolving credit facility consisted of a specific first mortgage on substantially all of PNG's property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings. (d) Collateral for the US$ MTNs is certain SEMCO assets. (e) Collateral for the CINGSA Senior secured loan is certain CINGSA assets, Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan. (f) PNG debentures totaling $33.3 million have been sold to ACI (Note 4 ) (g) Borrowings on the facility can be by way of U.S. base rate loans, U.S . prime loans, or LIBOR loans. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2018 | |
ASSET RETIREMENT OBLIGATIONS [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | 16. ASSET RETIREMENT OBLIGATIONS As at December 31, 2018 December 31, 2017 Balance, beginning of year $ 88.3 $ 81.6 Obligations acquired (note 3) 399.1 — New obligations 3.3 1.5 Obligations settled (4.2) (4.0) Disposals (1.6) — Revision in estimated cash flow 3.8 6.0 Accretion expense (a) 12.3 4.4 Foreign exchange translation 20.3 (0.9) Reclassified to liabilities associated with assets held for sale (note 5) (10.8) (0.3) Total 510.5 88.3 Less current portion (included in accounts payable and accrued liabilities) (9.9) — Balance, end of year $ 500.6 $ 88.3 (a) The majority of accretion expense is recorded through the Consolidated Statement of Income. Certain amounts relating to Washington Gas’ Utility asset retirement obligations are recorded through regulatory liabilities on the Consolidated Balance Sheets due to regulatory treatment. The majority of the asset retirement obligations are associated with distribution and transmission systems in the Utilities segment . AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2018 was $770.0 million ( December 31, 2017 - $232.9 million). The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 1.5 and 8.5 percent and are expected to be incurred between 2019 and 2064 . No assets have been legally restricted for settlement of the estimated liability. |
ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS | 12 Months Ended |
Dec. 31, 2018 | |
ENVIRONMENTAL MATTERS [Abstract] | |
ENVIRONMENTAL MATTERS | 17. ENVIRONMENTAL MATTERS AltaGas is subject to federal, provincial, state and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to control environmental effects. Almost all of the environmental liabilities AltaGas has recorded are for costs expected to be incurred to remediate sites where AltaGas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following: · the complexity of the site; · changes in environmental laws and regulations at the federal, state and local levels; · the number of regulatory agencies or other parties involved; · new technology that renders previous technology obsolete or experience with existing technology that proves ineffective; · the level of remediation required; and · variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site. AltaGas has identified up to twelve sites where it or its predecessors may have operated MGPs. In connection with these operations, AltaGas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others. At December 31, 2018, a liability of $15.4 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2017 - $nil ) in the Consolidated Balance Sheets under the line items “ accounts payable and accrued liabilities and other long-term liabilities”. These estimates principally include the minimum liabilities associated with a range of environmental response costs expected to be incurred. At December 31, 2018, AltaGas estimated the maximum liability associated with all of its sites to be approximately $40.1 million (December 31, 2017 - $nil ). The estimates were determined by AltaGas’ environmental experts, based on experience in remediating MGP sites and advice from legal counsel and environmental consultants. The variation between the recorded and estimated maximum liability primarily results from differences in the number of years that will be required to perform environmental response processes and the extent of remediation that may be required. At December 31, 2018, AltaGas reported a regulatory asset of $19.9 million (December 31, 2017 - $13.9 million) for the portion of environmental response costs that are expected to be recoverable in future rates. |
OTHER LONG-TERM LIABILITIES
OTHER LONG-TERM LIABILITIES | 12 Months Ended |
Dec. 31, 2018 | |
OTHER LONG-TERM LIABILITIES [Abstract] | |
OTHER LONG-TERM LIABILITIES | 18. OTHER LONG-TERM LIABILITIES As at December 31, 2018 December 31, 2017 Deferred lease payable $ 13.1 $ 2.4 Deferred revenue 3.9 3.8 Customer advances for construction 58.6 40.9 Sundance B PPA termination expense (a) 2.0 4.0 NTL liability (b) — 142.0 Lease inducement 2.7 3.1 Merger commitments 21.4 — Other long-term liabilities 20.3 5.7 $ 122.0 $ 201.9 (a) On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”. (b) The NTL liability has been reclassified as liabilities associated with assets held for sale (Note 5). |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2018 | |
INCOME TAXES [Abstract] | |
INCOME TAXES | 19. INCOME TAXES Year ended December 31 2018 2017 Income (loss) before income taxes - consolidated $ (716.9) $ 66.4 Statutory income tax rate (%) 27.0 27.0 Expected taxes at statutory rates $ (193.6) $ 17.9 Add (deduct) the tax effect of: Permanent differences (1.0) 9.5 Statutory and other rate differences (19.6) (30.5) Rate adjustment for change in tax rates 1.3 (34.1) Deferred income tax recovery on regulated assets (7.3) (7.4) Tax differences on divestitures and transactions (32.3) 6.9 Non-controlling interests 4.7 — Change in valuation allowance (22.3) 4.2 Other 6.9 — $ (263.2) $ (33.5) Income tax provision Current Canada 23.7 18.0 United States 0.7 12.5 $ 24.4 $ 30.5 Deferred Canada (166.1) (7.4) United States (121.5) (56.6) $ (287.6) $ (64.0) Effective income tax rate (%) 36.7 (50.5) Net deferred income tax liabilities were composed of the following: As at December 31, 2018 December 31, 2017 PP&E and intangible assets $ 1,764.6 $ 726.5 Regulatory assets (166.3) 22.8 Tax pools, deferred financing and compensation (453.6) (302.3) Other (209.9) (59.3) Valuation allowance 23.1 53.7 $ 957.9 $ 441.4 The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation's balance sheets at enacted tax rates. The TCJA in the U . S . became law on December 22, 2017. The law includes significant changes to the U.S. corporate income tax system, including a federal corporate rate reduction from 35 percent to 21 percent beginning in 2018, changes to capital depreciation, limitations on the deductibility of interest expense and executive compensation, and the transition of U.S. international taxation from a worldwide tax system to a territorial tax system. The B.C. government increased the corporate tax rate to 12 percent from 11 percent beginning in 2018. As at December 31, 2018 , the Corporation had tax - effected non - capital losses of approximately $ 392. 1 million, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 203 8 . Uncertain Tax Positions The Corporation recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that has greater than 50 percent likelihood of being realized upon settlement with the taxing authorities. On an annual basis, the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada, AltaGas' federal and provincial tax returns for the years 2012 to 2017 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns filed for the years 2012 to 2017 remain subject to examination by the taxation authorities. Management determined that the following provision was required for uncertainty on income taxes during the year: Year ended December 31 2018 2017 Balance, beginning of year $ 5.9 $ 2.2 Net changes during the year (3.7) 3.7 Balance, end of year $ 2.2 $ 5.9 |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 12 Months Ended |
Dec. 31, 2018 | |
REGULATORY ASSETS AND LIABILITIES [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | 20. REGULATORY ASSETS AND LIABILITIES AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheets when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statement of Income by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statement of Income in future periods when the amounts are reflected in customer rates . If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA. If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities. The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as of December 31, 2018 and 2017 , over which the Corporation expects to realize or settle the assets or liabilities: As at December 31, 2018 December 31, 2017 Recovery Period Regulatory assets - current Deferred cost of gas (a) $ 20.4 $ 0.5 Less than one year Deferred property taxes — 0.3 Less than one year Other 0.6 0.3 Less than one year $ 21.0 $ 1.1 Regulatory assets - non-current Deferred regulatory costs and rate stabilization adjustment mechanism (a)(b) $ 215.5 $ 20.5 1 - 3 years Pipeline rehabilitation costs — 0.3 Various Future recovery of pension and other retirement benefits (a) 192.9 113.9 Various Future recovery of non-retirement employee benefits (a)(c) 21.3 — Various Deferred pension costs (d) 7.8 — 1 years Deferred environmental costs (a)(e) 19.9 13.9 1 - 10 years Deferred loss on reacquired debt (a)(f) 109.3 2.5 1 - 15 years Deferred depreciation and amortization — 23.3 Various Deferred future income taxes (a)(g) 67.0 104.7 Various Deferred customer retention program amortization — 16.5 Various Revenue deficiency account — 31.0 Various Other 29.3 2.0 Various $ 663.0 $ 328.6 Regulatory liabilities - current Deferred cost of gas $ 71.2 $ 9.0 Less than one year Refundable tax credit (h) 3.8 1.9 Less than one year Federal income tax rate change (i) 26.2 — Less than one year Other 13.7 — Less than one year $ 114.9 $ 10.9 Regulatory liabilities - non-current Option fees deferral (a) $ — $ 4.3 Various Refundable tax credit (h) 6.1 7.5 Various Future expense of pension and other retirement benefits (a) 166.7 — Various Future removal and site restoration costs (j) 514.7 153.3 3 - 56 years Deferred loss on reacquired debt 1.8 — Various Federal income tax rate change (a)(i) 698.4 101.8 Various Insurance recovery of environmental costs — 0.3 2 years Other 5.1 1.4 Various $ 1,392.8 $ 268.6 (a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions. (b) Includes fair value of derivatives, which are not included in customer bills until settled. (c) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator. (d) Relates to cos ts not recoverable through rates in the District of Columbia jurisdiction. However, Washington Ga s is allowed to amortize these prior unrecovered pension and other post-retirement benefits through 2019 . (e) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates. (f) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. This also includes a fair value adjustment of $89 million recorded on the WGL Acquisition (Note 3). (g) This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates. (h) On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology. (i) The TCJA was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers. (j) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment . |
ACCUMULATED OTHER COMPREHENSIVE
ACCUMULATED OTHER COMPREHENSIVE INCOME | 12 Months Ended |
Dec. 31, 2018 | |
ACCUMULATED OTHER COMPREHENSIVE INCOME [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | 21. ACCUMULATED OTHER COMPREHENSIVE INCOME ($ millions) Available- for-sale Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Equity investee Total Opening balance, January 1, 2018 $ (7.1) $ (11.4) $ (129.0) $ 342.9 $ 3.7 $ 199.1 OCI before reclassification — (14.1) (90.6) 458.5 2.1 355.9 Amounts reclassified from OCI — 0.7 — — — 0.7 Adoption of ASU No. 2016-01 (note 2) 7.1 — — — — 7.1 Curtailment of DB and PRB plan — 4.2 — — — 4.2 Current period OCI (pre-tax) 7.1 (9.2) (90.6) 458.5 2.1 367.9 Income tax on amounts retained in AOCI — 3.3 10.4 — — 13.7 Income tax on amounts reclassified to earnings — (0.2) — — — (0.2) Income tax on amounts related to curtailment of DB and PRB plan — (1.5) — — — (1.5) Net current period OCI 7.1 (7.6) (80.2) 458.5 2.1 379.9 Ending balance, December 31, 2018 $ — $ (19.0) $ (209.2) $ 801.4 $ 5.8 $ 579.0 Opening balance, January 1, 2017 $ 19.8 $ (11.3) $ (135.6) $ 526.3 $ 5.9 $ 405.1 OCI before reclassification (30.3) (1.3) 6.6 (183.4) (2.2) (210.6) Amounts reclassified from AOCI — 1.3 — — — 1.3 Current period OCI (pre-tax) (30.3) — 6.6 (183.4) (2.2) (209.3) Income tax on amounts retained in AOCI 3.4 0.3 — — — 3.7 Income tax on amounts reclassified to earnings — (0.4) — — — (0.4) Net current period OCI (26.9) (0.1) 6.6 (183.4) (2.2) (206.0) Ending balance, December 31, 2017 $ (7.1) $ (11.4) $ (129.0) $ 342.9 $ 3.7 $ 199.1 Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year ended December 31, 2018 Year ended December 31, 2017 Defined benefit pension and PRB plans Operating and administrative expense $ 0.7 $ 1.3 Deferred income taxes Income tax expenses – deferred (0.2) (0.4) $ 0.5 $ 0.9 |
FINANCIAL INSTRUMENTS AND FINAN
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT | 12 Months Ended |
Dec. 31, 2018 | |
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT [Abstract] | |
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT | 22. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities. Fair Value Hierarchy AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value. Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date. Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within level 1 are observable for the asset or liability either directly or indirectly. AltaGas enters into derivative instruments in the futures, over-the-counter and retail markets to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas and NGL derivative contracts were calculated using forward prices based on published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model. Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available. A variety of valuation methodologies are used to determine the fair value of Level 3 derivative contracts, including developed valuation inputs and pricing models. The prices used in the valuations are corroborated using multiple pricing sources, and the Corporation periodically conducts assessments to determine whether each valuation model is appropriate for its intended purpose. Level 3 derivatives include physical contracts at illiquid market locations with no observable market data, long-dated positions where observable pricing is not available over the life of the contract, contracts valued using historical spot price volatility assumptions, and valuations using indicative broker quotes for inactive market locations. The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments: Other current liabilities - the carrying amounts approximate fair value because of the short maturity of these instruments. Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. The fair value of level 3 long term debt was determined by taking the present value of the debt securities’ future cash flows discounted at interest rates that reflect market conditions as of the measurement date. The discount rate is based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer. Risk management assets and liabilities - the fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of level 3 derivative contracts was calculated using internally developed valuation inputs and pricing models. Equity s ecurities – the fair value of equity securities was calculated using quoted market prices. Loans and receivables – the fair value of these assets was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. December 31, 2018 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 99.0 $ — $ 68.3 $ 30.7 $ 99.0 Risk management assets - non-current 49.0 — 18.0 31.0 49.0 Equity securities (b) 8.4 8.4 — — 8.4 Fair value through regulatory assets/liabilities (a) Risk management assets - current 15.1 — 2.7 12.4 15.1 Risk management assets - non-current 8.7 — — 8.7 8.7 Amortized cost Loans and receivables (b) 45.0 — 45.2 — 45.2 $ 225.2 $ 8.4 $ 134.2 $ 82.8 $ 225.4 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 72.0 $ — $ 41.3 $ 30.7 $ 72.0 Risk management liabilities - non-current 103.4 — 15.3 88.1 103.4 Fair value through regulatory assets/liabilities (a) Risk management liabilities - current 17.3 — 2.9 14.4 17.3 Risk management liabilities - non-current 109.6 — 0.1 109.5 109.6 Amortized cost Current portion of long-term debt 890.2 — 884.4 — 884.4 Long-term debt 8,066.9 — 6,027.6 2,012.7 8,040.3 Other current liabilities (c) 11.2 — 11.2 — 11.2 Other long-term liabilities (c) 2.0 — 2.0 — 2.0 $ 9,272.6 $ — $ 6,984.8 $ 2,255.4 $ 9,240.2 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non - financial liabilities. December 31, 2017 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income Risk management assets - current $ 38.6 $ — $ 38.6 $ — $ 38.6 Risk management assets - non-current 15.9 — 15.9 — 15.9 Equity securities (a) 95.0 95.0 — — 95.0 Amortized cost Loans and receivables (a) 75.0 — 85.6 — 85.6 $ 224.5 $ 95.0 $ 140.1 $ — $ 235.1 Financial liabilities Fair value through net income Risk management liabilities - current $ 57.6 $ — $ 57.6 $ — $ 57.6 Risk management liabilities - non-current 13.8 — 13.8 — 13.8 Amortized cost Current portion of long-term debt 188.9 — 189.6 — 189.6 Long-term debt 3,436.5 — 3,568.3 — 3,568.3 Other current liabilities (b) 22.4 — 22.4 — 22.4 Other long-term liabilities (b) 146.0 — 147.7 — 147.7 $ 3,865.2 $ — $ 3,999.4 $ — $ 3,999.4 (a) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (b) Excludes non - financial liabilities. The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments at December 31, 2018: Net Fair Value Valuation Technique Unobservable Inputs Range Natural gas $ (144.1) Discounted Cash Flow Natural Gas Basis Price (per dekatherm) ( $1.40 ) - $7.28 Natural gas $ (4.4) Option Model Natural Gas Basis Price (per dekatherm) ( $1.37 ) - $5.07 Annualized Volatility of Spot Market Natural Gas 37.46% - 900.98% Electricity $ (14.7) Discounted Cash Flow Electricity Congestion Price (per megawatt hour) ( $8.28 ) - $84.44 The following table provides a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy: For the year ended December 31 2018 2017 Natural Gas Electricity Total Natural Gas Electricity Total Balance, beginning of year $ — $ — $ — $ — $ — $ — Acquired (note 3) (136.1) (10.6) (146.7) — — — Realized and unrealized losses: — — — Recorded in income (8.3) (6.5) (14.8) Recorded in regulatory assets (5.9) — (5.9) — — — Transfers out of Level 3 7.3 — 7.3 — — — Purchases — 6.4 6.4 — — — Settlements 0.3 (3.4) (3.1) — — — Foreign exchange translation (5.8) (0.6) (6.4) Balance, end of year $ (148.5) $ (14.7) $ (163.2) $ — $ — $ — Transfers between different levels of the fair value hierarchy may occur based on fluctuations in the valuation and on the level of observable inputs used to value the instruments from period to period. Transfers into and out of the different levels of the fair value hierarchy are presented at the fair value as of the beginning of the year . Transfers out of Level 3 during the year ended December 31, 2018 were due to an increase in valuations using observable market inputs. Transfer s into Level 3 during the year ended December 31, 2018 were due to an increase in unobservable market inputs used in valuations. Realized and Unrealized Losses Recorded to Income for Level 3 Measurements For the year ended December 31 2018 2017 Recorded to revenue Commodity contracts $ (11.1) $ — Recorded to cost of sales Commodity contracts (3.7) — $ (14.8) $ — Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income For the year ended December 31 2018 2017 Natural gas $ (2.2) $ 2.2 Storage optimization — 2.7 NGL frac spread 40.0 (11.7) Power 9.3 (20.8) Foreign exchange 33.7 (34.9) $ 80.8 $ (62.5) Offsetting of Derivative Assets and Derivative Liabilities Certain of AltaGas’ risk management contracts are subject to master netting arrangements that create a legally enforceable right for a counterparty to offset the related financial assets and financial liabilities. As part of these master netting agreements, cash, letters of credit and parental guarantees may be required to be posted or obtained from counterparties in order to mitigate credit risk related to both derivative and non-derivative positions. Collateral balances are also offset against the related counterparties’ derivative positions to the extent the application would not result in the over-collateralization of those derivative positions on the balance sheet. December 31, 2018 Risk management assets (a) Gross amounts of recognized assets/liabilities Gross amounts offset in balance sheet Netting of collateral Net amounts presented in balance sheet Natural gas $ 200.8 $ (82.0) $ — $ 118.8 NGL frac spread 18.7 (0.7) — 18.0 Power 42.8 (7.8) — 35.0 $ 262.3 $ (90.5) $ — $ 171.8 Risk management liabilities (b) Natural gas $ 340.4 $ (82.0) $ (3.3) $ 255.1 NGL frac spread 2.7 (0.7) — 2.0 Power 50.6 (7.8) 1.2 44.0 Foreign exchange 1.2 — — 1.2 $ 394.9 $ (90.5) $ (2.1) $ 302.3 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non - current) balance of $57.7 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non - current) balance of $213.0 million. December 31, 2017 Risk management assets (a) Gross amounts of recognized assets/liabilities Gross amounts offset in balance sheet Netting of collateral Net amounts presented in balance sheet Natural gas $ 41.0 $ (6.2) $ — $ 34.8 NGL frac spread 1.3 (0.3) — 1.0 Power 17.7 (0.7) — 17.0 Foreign exchange 1.7 — — 1.7 $ 61.7 $ (7.2) $ — $ 54.5 Risk management liabilities (b) Natural gas $ 35.1 $ (6.2) $ — $ 28.9 NGL frac spread 25.3 (0.3) — 25.0 Power 14.0 (0.7) 4.2 17.5 $ 74.4 $ (7.2) $ 4.2 $ 71.4 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non - current) balance of $15.9 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $ 57.6 million and risk management liabilities (non - current) balance of $13.8 million. Cash Collateral The following table presents collateral not offset against risk management assets and liabilities: December 31, 2018 December 31, 2017 Collateral posted with counterparties $ 27.6 $ — Cash collateral held representing an obligation $ 0.8 $ — Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets. Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2018 and 2017, AltaGas had not posted any collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if the most intrusive credit-risk-related contingent features underlying these agreements were triggered: December 31, 2018 December 31, 2017 Risk management liabilities with credit-risk-contingent features $ 14.7 $ — Maximum potential collateral requirements $ 7.5 $ — Risks associated with financial instruments AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk. Commodity Price Risk AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes. Natural Gas In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2023. In addition, AltaGas may enter into financial derivative contracts as part of WGL’s asset optimization program. WGL optimized the value of its long-term natural gas transportation and storage capacity resources during periods when these resources are not being used to physically serve utility customers. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2018 and 2017 : December 31, 2018 Fixed price (per GJ) Period (months) Notional volume (GJ) Fair Value ($ millions) Sales 1.07 to 12.19 1-178 858,640,810 19.0 Purchases 0.69 to 16.26 1-179 1,638,207,391 (179.5) Swaps 2.56 to 15.37 1-231 621,578,572 20.9 December 31, 2017 Fixed price (per GJ) Period (months) Notional volume (GJ) Fair Value ($ millions) Sales 0.42 to 6.89 1-60 94,804,039 14.8 Purchases 0.52 to 6.40 1-48 61,980,315 (16.8) Swaps 2.86 to 9.38 1-10 6,039,642 7.9 NGL Frac Spread AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2018 and 2017 : December 31, 2018 Fixed price Period (months) Notional volume Fair Value ($ millions) Propane swaps $38.89 to $47.63/bbl 1-12 1,725,114 Bbl 12.6 Butane swaps $52.95 to $55.26/bbl 1-12 74,371 Bbl 1.2 Crude oil swaps $79.64 to $86.28/bbl 1-12 329,230 Bbl 6.0 Natural gas swaps $1.38 to $1.68/GJ 1-12 9,490,365 GJ (3.8) December 31, 2017 Fixed price Period (months) Notional volume Fair Value ($ millions) Propane swaps $28.77 to $49.21 /Bbl 1-12 1,992,927 Bbl (10.9) Butane swaps $47.83 to $54.67 /Bbl 1-12 130,088 Bbl (0.3) Crude oil swaps $61.05 to $75.64 /Bbl 1-12 518,665 Bbl (4.4) Natural gas swaps $0.42 to $2.27 /GJ 1-12 11,428,515 GJ (8.4) Power AltaGas sells power to the Alberta Electric System Operator at market prices as well as to commercial and industrial users in Alberta at fixed prices. AltaGas also sells power through its WGL Energy Services affiliate, to commercial, industrial and mass market users within the PJM R egional Transmission O rganization at fixed and market prices. AltaGas' strategy is to mitigate the cash flow risk to Alberta power prices to provide predictable earnings. Therefore, AltaGas uses third party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 202 3 . As at December 31, 2018, AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2018 and 2017 : December 31, 2018 Fixed price (per MWh) Period (months) Notional volume (MWh) Fair Value ($ millions) Power sales 26.90 to 95.03 1-60 11,881,575 (1.9) Power purchases 25.50 to 50.25 1-42 8,507,874 16.4 Swap purchases (6.07) to 76.18 1-48 20,957,180 (22.3) December 31, 2017 Fixed price (per MWh) Period (months) Notional volume (MWh) Fair Value ($ millions) Power sales 38.20 to 95.03 1-60 2,169,321 (2.5) Power purchases 58.50 1-12 17,520 (4.5) Swap purchases 37.50 to 63.50 1-48 1,563,160 6.5 The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2018 : Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) Alberta power price $1/MWh 0.3 PJM power price $1/MWh 1.2 AECO natural gas price $0.50/GJ 5.9 NYMEX natural gas price $0.50/GJ 31.5 NGL frac spread: Propane $1/Bbl 1.7 Butane $1/Bbl 0.1 Western Texas Intermediate (WTI) crude oil $1/Bbl 0.3 Natural gas $0.50/GJ 4.7 Foreign Exchange Risk AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. As at December 31, 2018 and 2017, AltaGas did not have any outstanding foreign exchange forward contracts. AltaGas may also designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2018 , AltaGas designated US$1,494.0 million of outstanding debt as a net investment hedge ( December 31, 2017 - $ nil ). For the year ended December 31, 2018 , AltaGas incurred an after-tax unrealized loss of $80.2 million arising from the translation of debt in OCI ( 2017 - after-tax unrealized gain of $ 6.6 million). To mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas entered into foreign currency option contracts with an aggregate notional value of approximately US$1.2 billion which expired in May 2018. These foreign currency option contracts do not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the year ended December 31, 2018, an unrealized gain of $34.3 million and a realized loss of $36.0 million were recognized in revenue in relation to these contracts (2017 – unrealized losses of $34.3 million). During the second quarter of 2018, AltaGas entered into foreign exchange forward contracts with an aggregate notional value of $3.2 billion which settled in July 2018. These foreign currency derivatives do not qualify for hedge accounting. For t he year ended December 31, 2018, a realized gain of $1.3 million was recognized in income in relation to these forwards (2017 - $nil ). Interest Rate Risk AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2018 , approximately 59 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates. In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2018 . Credit Risk Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract. AltaGas' credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business. AltaGas' maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2018 , AltaGas had no concentration of credit risk with a single counterparty. Weather Related Instruments WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the period from close of the WGL Acquisition to December 31, 2018, pre-tax losses of $1 million were recorded related to these instruments (2017 - $nil ). Accounts Receivable Past Due or Impaired AltaGas had the following past due or impaired accounts receivable (AR): As at December 31, 2018 Total AR accruals Receivables impaired Less than 30 days 31 to 60 days 61 to 90 days Over 90 days Trade receivable $ 1,574.6 $ 447.5 $ 54.7 $ 961.5 $ 74.1 $ 12.8 $ 24.0 Other 27.6 — — 27.5 — — 0.1 Allowance for credit losses (54.7) — (54.7) — — — — $ 1,547.5 $ 447.5 $ — $ 989.0 $ 74.1 $ 12.8 $ 24.1 As at December 31, 2017 Total AR accruals Receivables impaired Less than 30 days 31 to 60 days 61 to 90 days Over 90 days Trade receivable $ 383.0 $ 184.6 $ 2.4 $ 187.0 $ 7.9 $ 1.4 $ (0.3) Other 2.3 — — 2.3 — — — Allowance for credit losses (2.4) — (2.4) — — — — $ 382.9 $ 184.6 $ — $ 189.3 $ 7.9 $ 1.4 $ (0.3) Allowance for credit losses December 31, 2018 December 31, 2017 Balance, beginning of year $ 2.4 $ 2.5 Foreign exchange translation 0.1 (0.1) New allowance (a) 53.1 0.4 Change in allowance (0.9) — Allowance applied to uncollectible customer accounts — (0.4) Balance, end of year $ 54.7 $ 2.4 (a) Upon close of the WGL Acquisition, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million. Liquidity Risk Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas' objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required. AltaGas had the following contractual maturities with respect to financial liabilities: Contractual maturities by period As at December 31, 2018 Total Less than 1 year 1-3 years 4-5 years After 5 years Accounts payable and accrued liabilities $ 1,488.2 $ 1,488.2 $ — $ — $ — Dividends payable 22.0 22.0 — — — Short-term debt 1,209.9 1,209.9 — — — Other current liabilities (a) 11.2 11.2 — — — Other long-term liabilities (a) 2.0 — 2.0 — — Risk management contract liabilities 302.3 89.3 113.3 33.3 66.4 Current portion of long-term debt (b) 888.5 888.5 — — — Long-term debt (b) 8,014.8 — 3,063.4 1,592.6 3,358.8 $ 11,938.9 $ 3,709.1 $ 3,178.7 $ 1,625.9 $ 3,425.2 (a) Excludes non - financial liabilities (b) Excludes deferred financing costs and discounts Contractual maturities by period As at December 31, 2017 Total Less than 1 year 1-3 years 4-5 years After 5 years Accounts payable and accrued liabilities $ 415.3 $ 415.3 $ — $ — $ — Dividends payable 32.0 32.0 — — — Short-term debt 46.8 46.8 — — — Other current liabilities (a) 22.4 22.4 — — — Other long-term liabilities (a) 146.0 — 25.7 20.8 99.5 Risk management contract liabilities 71.4 57.6 11.1 2.7 — Current portion of long-term debt (b) 188.9 188.9 — — — Long-term debt (b) 3,450.9 — 1,009.1 363.8 2,078.0 $ 4,373.7 $ 763.0 $ 1,045.9 $ 387.3 $ 2,177.5 (a) Excludes non - financial liabilities (b) Excludes deferred financing costs and discounts |
REVENUE
REVENUE | 12 Months Ended |
Dec. 31, 2018 | |
REVENUE [Abstract] | |
Revenue | 23. REVENUE The following table disaggregates revenue by major sources for the year ended December 31, 2018: Year ended December 31, 2018 Utilities Midstream Power Corporate Total Revenue from contracts with customers Commodity sales contracts $ — $ 665.2 $ 497.5 $ — $ 1,162.7 Midstream service contracts — 205.0 — — 205.0 Gas sales and transportation services 1,684.3 — — — 1,684.3 Storage services 35.4 — — — 35.4 Other 10.7 0.6 25.1 — 36.4 Total revenue from contracts with customers $ 1,730.4 $ 870.8 $ 522.6 $ — $ 3,123.8 Other sources of revenue Revenue from alternative revenue programs (a) $ 21.7 $ — $ — $ — $ 21.7 Leasing revenue (b) 0.6 96.6 354.9 — 452.1 Risk management and trading activities (c)(d) 1.0 377.6 268.5 (2.9) 644.2 Other (1.1) (0.4) 16.0 0.4 14.9 Total revenue from other sources $ 22.2 $ 473.8 $ 639.4 $ (2.5) $ 1,132.9 Total revenue $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5) $ 4,256.7 (a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d). (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues of $ 264.2 million associated with the GAIL Global (USA) L NG LLC (GAIL) contract, which are in scope of ASC 606, are reported in the risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The contract has a term of 20 years and began on March 31, 2018. Revenue Recognition The following is a description of the Corporation’s revenue recognition policy by major sources of revenue from contracts with customers and segment. Utilities segment Gas sales and transportation services Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts are “at-will” as customers may cancel their service at any time, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed. Gas storage services Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one -year. Midstream segment Commodity sales A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one-year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. Commodity sales also include gas sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on the amount of gas delivered to the customer. Revenue is recognized based on the amount the Company is entitled to invoice the customer. Midstream service contracts AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows: Fee-for-service – The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount. Take-or-pay – The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires becomes remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make-up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount. Power segment For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments. For commodity sales contracts that do not meet the definition of a lease, derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. Commodity Sales Energy generated from commercial solar and combined heating and power assets is sold under long term power purchase agreements with a general duration of 20 years. These long term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. Commodity sales also include electricity sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on meter readings or the amount of energy delivered to the customer. Revenue is recognized based on the amount the Company is entitled to invoice the customer. Contract Balances As at December 31, 2018, a contract asset of $11.5 million has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2017 – $nil ). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract. In addition, at December 31, 2 018 there is a contr act asset of $47.3 million (December 31, 2017 - $nil ) recorded within accounts receivable on the Consolidated Balance Sheets for WGL Energy Systems’ unbilled revenue relating to design-build construction contracts. The contract asset represents unbilled amounts typically resulting from sales under contracts when the cost-to-cost method of revenue recognition is utilized, and revenue recognized exceeds the amount billed to the customer. Right to payment is achieved when the projects are formally “accepted” by the federal government. In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset. Accordingly, the receivable was reclassified as held for sale (Note 5) and a $6.0 million provision was recorded on the asset (Note 10). Contract liabilities of $2.2 million (2017 - $nil ) have been recorded within other current liabilities on the Consolidated Balance Sheets. The contract liabilities consist of advance payments and billings in excess of revenue recognized and deferred revenue. Contract assets and liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period. Transaction price allocated to the remaining obligations The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2018: 2019 2020 2021 2022 2023 > 2023 Total Midstream service contracts $ 52.2 $ 55.7 $ 32.3 $ 31.9 $ 28.0 $ 192.4 $ 392.5 Gas sales and transportation services 0.6 0.6 0.6 0.6 0.6 3.2 6.2 Storage services 36.7 36.3 36.3 36.3 36.3 299.8 481.7 Other 37.0 10.5 1.6 0.8 0.8 3.2 53.9 Subtotals $ 126.5 $ 103.1 $ 70.8 $ 69.6 $ 65.7 $ 498.6 $ 934.3 AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided. |
SHAREHOLDERS' EQUITY
SHAREHOLDERS' EQUITY | 12 Months Ended |
Dec. 31, 2018 | |
SHAREHOLDERS' EQUITY [Abstract] | |
SHAREHOLDERS' EQUITY | 24. SHAREHOLDERS’ EQUITY Authorization AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue preferred shares not to exceed 50 percent of the voting rights attached to the issued and outstanding common shares. Premium Dividend TM , Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan) The Plan consists of three components: a Premium Dividend™ component, a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended effective December 18, 2018. The Plan provides eligible holders of common shares with the opportunity to, at their election, either: (1) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) of the common shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan); or (2) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) on the applicable dividend payment date and have these additional common shares of AltaGas exchanged for a cash payment equal to 101 percent of the reinvested amount (the Premium Dividend TM component of the Plan). In addition, the Plan provides shareholders who are enrolled in the Dividend Reinvestment component of the Plan with the opportunity to purchase new common shares at the average market price (with no discount) on the applicable dividend payment date (the Optional Cash Purchase component of the Plan). Each of the components of the Plan are subject to prorating and other limitations on availability of new common shares in certain events. The "average market price", in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium Dividend TM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements. Common Shares Issued and Outstanding Number of shares Amount January 1, 2017 166,906,833 $ 3,773.4 Shares issued for cash on exercise of options 240,125 6.5 Deferred taxes on share issuance cost — (8.3) Shares issued under DRIP 8,132,258 236.3 December 31, 2017 175,279,216 4,007.9 Shares issued on conversion of subscription receipts, net of issuance costs 84,510,000 2,305.6 Shares issued for cash on exercise of options 57,275 1.3 Deferred taxes on share issuance costs — 13.3 Shares issued under DRIP 15,377,575 325.8 Issued and outstanding at December 31, 2018 275,224,066 $ 6,653.9 Preferred Shares As at December 31, 2018 December 31, 2017 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 5,511,220 $ 137.8 5,511,220 $ 137.8 Series B 2,488,780 62.2 2,488,780 62.2 Series C 8,000,000 205.6 8,000,000 205.6 Series E 8,000,000 200.0 8,000,000 200.0 Series G 8,000,000 200.0 8,000,000 200.0 Series I 8,000,000 200.0 8,000,000 200.0 Series K 12,000,000 300.0 12,000,000 300.0 Washington Gas $4.80 series 150,000 19.7 — — $4.25 series 70,600 9.4 — — $5.00 series 60,000 7.9 — — Share issuance costs, net of taxes (27.9) (27.9) Fair value adjustment on WGL Acquisition (note 3) 4.1 — 52,280,600 $ 1,318.8 52,000,000 $ 1,277.7 The following table outlines the characteristics of the cumulative redeemable preferred shares (a) : Current yield Annual dividend per share (b) Redemption price per share Redemption and conversion option date (c)(d) Right to convert into (d) AltaGas Series A (e) 3.38% $0.845 $25 September 30, 2020 Series B Series B (f) Floating (f) Floating (f) $25 September 30, 2020 (g) Series A Series C (h) 5.29% US$1.3225 US$25 September 30, 2022 Series D Series E (e) 5.393% $1.34825 $25 December 31, 2023 Series F Series G (e) 4.75% $1.1875 $25 September 30, 2019 Series H Series I (i) 5.25% $1.3125 $25 December 31, 2020 Series J Series K (j) 5.00% $1.25 $25 March 31, 2022 Series L Washington Gas $4.80 series 4.27% US$4.80 US$101 n/a n/a $4.25 series 4.27% US$4.25 US$105 n/a n/a $5.00 series 4.27% US$5.00 US$102 n/a n/a (a) The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares , Series F Shares , Series H Shares , and Series J Shares , and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares , Series H Shares , Series J Shares , and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. (b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. (c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. (d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter. (e) Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five -year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). (f) Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2018, the floating quarterly dividend rate for Series B Shares is $0.26938 per share for the period starting December 31, 2018 to, but excluding, March 31, 2019. (g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. (h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent. (i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum. (j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum. Share Option Plan AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at December 31, 2018 , 21,213,224 shares were reserved for issuance under the plan. As at December 31, 2018 , options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four -year period. As at Decem ber 31, 2018 , unexpensed fair value of share option compensation cost associated with future periods was $3.7 million ( December 31, 2017 - $1.3 million). The following table summarizes information about the Corporation’s share options: As at December 31, 2018 December 31, 2017 Options outstanding Options outstanding Number of options Exercise price (a) Number of options Exercise price (a) Share options outstanding, beginning of year 4,533,761 $ 32.35 4,119,386 $ 32.39 Granted 2,811,460 16.69 848,000 30.80 Exercised (57,275) 20.68 (240,125) 24.63 Forfeited (878,013) 36.47 (193,500) 36.36 Expired (100,750) 14.60 — — Share options outstanding, end of year 6,309,183 $ 25.18 4,533,761 $ 32.35 Share options exercisable, end of year 2,897,723 $ 32.01 3,326,197 $ 31.93 (a) Weighted averag e . As at December 31, 2018 , the aggregate intrinsic value of the total options exercisable was $nil ( December 31, 2017 - $ 6.0 million), the total intrinsic value of options outstanding was $nil ( December 31, 2017 - $6.0 million) and the total intrinsic value of options exercised was $0.3 million ( December 31, 2017 - $1.4 million). The following table summarizes the employee share option plan as at December 31, 2018 : Options outstanding Options exercisable Weighted Weighted average Weighted Weighted average Number average remaining Number average remaining outstanding exercise price contractual life exercisable exercise price contractual life $14.24 to $18.00 2,322,635 $ 14.55 5.91 28,000 $ 17.10 1.33 $18.01 to $25.08 425,000 20.76 1.83 425,000 20.76 1.83 $25.09 to $50.89 3,561,548 32.65 3.48 2,444,723 34.14 2.95 6,309,183 $ 25.18 4.26 2,897,723 $ 32.01 2.77 The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows: Year ended December 31 2018 2017 Fair value per option ($) 1.27 1.91 Risk-free interest rate (%) 1.99 1.31 Expected life (years) 6 6 Expected volatility (%) 23.23 21.05 Annual dividend per share ($) (a) 1.18 2.12 Forfeiture rate (%) — — (a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as of the grant dates. MTIP and DSUP AltaGas has a MTIP for employees and executive officers, which includes RUs and PUs with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of DSUs to directors, officers and employees. DSUs granted under the DSUP vest immediately but settlement of the DSUs occurs when the individual ceases to be a director. PUs, RUs, and DSUs December 31, 2018 December 31, 2017 (number of units) Balance, beginning of year 564,549 364,839 Acquired (a) 5,291,621 — Granted 9,502,347 386,126 Additional units added by performance factor — 24,301 Vested and paid out (148,154) (221,775) Forfeited (66,522) (27,279) Units in lieu of dividends 55,934 38,337 Outstanding, end of year 15,199,775 564,549 (a) Upon close of the WGL Acquisition, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit. For the year ended December 31, 2018 , the compensation expense recorded for the MTIP and DSUP was $ 16.6 million ( 2017 - $9.1 million). As at December 31, 2018 , the unreco gnized compensation expense relating to the remaining vesting period for the MTIP was $26. 9 million ( December 31, 2017 - $8.4 million) and is expected to be recognized over the vesting period. |
NET INCOME PER COMMON SHARE
NET INCOME PER COMMON SHARE | 12 Months Ended |
Dec. 31, 2018 | |
NET INCOME PER COMMON SHARE [Abstract] | |
NET INCOME PER COMMON SHARE | 25. NET INCOME PER COMMON SHARE The following table summarizes the computation of net income per common share: Year ended December 31 2018 2017 Numerator: Net income (loss) applicable to controlling interests $ (435.1) $ 91.6 Less: Preferred share dividends (66.6) (61.3) Net income (loss) applicable to common shares $ (501.7) $ 30.3 Denominator: (millions) Weighted average number of common shares outstanding 222.6 171.0 Dilutive equity instruments (a) 0.1 0.3 Weighted average number of common shares outstanding - diluted 222.7 171.3 Basic net income (loss) per common share $ (2.25) $ 0.18 Diluted net income (loss) per common share $ (2.25) $ 0.18 (a) Includes all options that have a strike price lower than the share price of AltaGas' common shares as at December 31, 2018 and 2017 . For the year ended December 31, 201 8, 4.0 million of share options ( 2017 – 2.8 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive. |
OTHER INCOME
OTHER INCOME | 12 Months Ended |
Dec. 31, 2018 | |
OTHER INCOME [Abstract] | |
OTHER INCOME | 26. OTHER INCOME Year ended December 31 2018 2017 Losses from sale of assets $ (10.6) $ (2.7) Other components of net benefit cost (note 2) 18.9 — Interest income and other revenue 2.7 8.7 Gains (losses) on investments (10.1) 3.6 $ 0.9 $ 9.6 |
OPERATING LEASES
OPERATING LEASES | 12 Months Ended |
Dec. 31, 2018 | |
OPERATING LEASES [Abstract] | |
OPERATING LEASES | 27. OPERATING LEASES Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. The carrying value of property, plant, and equipment associated with these leases was $2. 5 billion as at December 31, 2018 ( December 31, 2017 - $3.0 billion). For the year ended December 31, 2018 , the total revenue earned from minimum lease payments was $285 . 1 million ( 2017 - $290.8 million) and from contingent rentals was $167.1 million ( 2017 - $175.6 million). The following table sets forth the future fixed minimum revenue related to the operating leases for the years ended December 31: 2019 194.4 2020 155.3 2021 111.9 2022 112.0 2023 104.2 |
PENSION PLANS AND RETIREE BENEF
PENSION PLANS AND RETIREE BENEFITS | 12 Months Ended |
Dec. 31, 2018 | |
PENSION PLANS AND RETIREE BENEFITS [Abstract] | |
PENSION PLANS AND RETIREE BENEFITS | 28. PENSION PLANS AND RETIREE BENEFITS The costs of the defined benefit and post-retirement benefit plans are based on management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits. Defined Contribution Plan AltaGas has a defined contribution (DC) pension plan for substantially all employees who are not members of defined benefit plans. The pension cost recorded for the DC plan was $15.4 million for the year ended December 31, 2018 ( 2017 - $8.4 million). Defined Benefit Plans AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including five in Canada and six in the United States. These benefit plans are partially funded except for three of the Canadian plans which are fully funded. Supplemental Executive Retirement Plan (SERP) AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account. Post-Retirement Benefits AltaGas has several post-retirement benefit plans for unionized and non-unionized employees, including one in Canada and four in the United States. The post- retirement benefit plan in Canada is limited to the payment of life insurance and health insurance premiums. This benefit plan is not funded. Post -retirement benefit plans in the United States provide certain medical and prescription drug benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree's age and years of service at retirement. Two of these benefit plans are partially funded and two of them are fully funded . AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed in 2016. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2019, and is expected to be filed with the pension regulators in 2020. Actuarial valuations are required annually for AltaGas’ U.S. defined benefit plans . The following defined benefit and post-retirement benefit plans were acquired in connection with the acquisition of WGL: Defined Benefit Plans: · Qualified Pension Plan - Washington Gas maintains a qualified, trusteed, non-contributory defined benefit pension plan covering most active and vested former employees of Washington Gas and certain employees of WGL subsidiaries. The non-contributory defined benefit pension plan is closed to all employees hired on or after January 1, 2010. · Supplemental Executive Retirement Plan (DB SERP) - several executive officers of Washington Gas participate in the non-funded DB SERP, a nonqualified pension plan. The DB SERP was closed to new entrants beginning January 1, 2010. · Defined Benefit Restoration Plan (DB Restoration) - a non-funded defined benefit restoration plan for the purpose of providing supplemental pension and pension-related benefits to a select group of management employees of Washington Gas. Post-retirement Benefit Plans: · Life Plan - Washington Gas provides life insurance benefits for retired employees of Washington Gas and certain employees of WGL subsidiaries. · Retiree Medical Plan – under this plan Washington Gas provides medical, prescription drug and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans for eligible retirees and dependents not yet receiving Medicare benefits. · Health Reimbursement Account (HRA) Plan – under this plan retirees age 65 and older and dependents receive an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace. Rabbi trusts have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans for a total of $89.3 million. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets. The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States: Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2018 Benefit Benefits Benefit Benefits Benefit Benefits Accrued benefit obligation Balance, beginning of year $ 165.6 $ 15.8 $ 303.8 $ 82.7 $ 469.4 $ 98.5 Plans disposed (note 4) (132.1) (13.6) — — (132.1) (13.6) Actuarial gain (0.8) (0.1) (67.7) (33.8) (68.5) (33.9) Current service cost 2.4 0.1 16.2 5.3 18.6 5.4 Member contributions — — — 2.1 — 2.1 Interest cost 1.2 0.1 38.0 10.9 39.2 11.0 Benefits paid (2.7) — (43.2) (13.4) (45.9) (13.4) Expenses paid — — (0.9) (0.1) (0.9) (0.1) Plan combinations 0.7 — 1,311.7 382.9 1,312.4 382.9 Plan amendments — (0.4) — — — (0.4) Foreign exchange translation — — 77.4 21.4 77.4 21.4 Balance, end of year $ 34.3 $ 1.9 $ 1,635.3 $ 458.0 $ 1,669.6 $ 459.9 Plan assets Fair value, beginning of year $ 115.2 $ 8.1 $ 248.7 $ 70.8 $ 363.9 $ 78.9 Plans disposed (note 4) (102.1) (8.1) — — (102.1) (8.1) Actual return on plan assets (0.3) — (54.7) (37.2) (55.0) (37.2) Employer contributions 3.4 — 7.6 2.5 11.0 2.5 Member contributions — — — 2.1 — 2.1 Benefits paid (2.7) — (43.2) (13.4) (45.9) (13.4) Expenses paid — — (0.9) (0.1) (0.9) (0.1) Plan combinations 0.3 — 1,133.2 732.7 1,133.5 732.7 Foreign exchange translation — — 63.4 33.8 63.4 33.8 Fair value, end of year $ 13.8 $ — $ 1,354.1 $ 791.2 $ 1,367.9 $ 791.2 Net amount recognized $ (20.5) $ (1.9) $ (281.2) $ 333.2 $ (301.7) $ 331.3 Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2017 Benefit Benefits Benefit Benefits Benefit Benefits Accrued benefit obligation Balance, beginning of year $ 150.0 $ 16.4 $ 290.5 $ 72.7 $ 440.5 $ 89.1 Actuarial loss (gain) 8.3 (1.6) 23.2 14.4 31.5 12.8 Current service cost 7.9 0.7 8.0 1.8 15.9 2.5 Member contributions 0.2 — — — 0.2 — Interest cost 5.8 0.6 11.7 2.9 17.5 3.5 Benefits paid (6.3) (0.3) (8.6) (3.2) (14.9) (3.5) Expenses paid (0.3) — (0.8) (0.1) (1.1) (0.1) Plan settlements — — — (0.5) — (0.5) Foreign exchange translation — — (20.2) (5.3) (20.2) (5.3) Balance, end of year $ 165.6 $ 15.8 $ 303.8 $ 82.7 $ 469.4 $ 98.5 Plan assets Fair value, beginning of year $ 101.5 $ 6.8 $ 226.9 $ 67.2 $ 328.4 $ 74.0 Actual return on plan assets 8.5 0.4 37.9 11.0 46.4 11.4 Employer contributions 11.6 1.2 9.5 0.6 21.1 1.8 Member contributions 0.2 — — — 0.2 — Benefits paid (6.3) (0.3) (8.6) (3.2) (14.9) (3.5) Expenses paid (0.3) — (0.8) (0.1) (1.1) (0.1) Foreign exchange translation — — (16.2) (4.7) (16.2) (4.7) Fair value, end of year $ 115.2 $ 8.1 $ 248.7 $ 70.8 $ 363.9 $ 78.9 Net amount recognized $ (50.4) $ (7.7) $ (55.1) $ (11.9) $ (105.5) $ (19.6) The following amounts were included in the Consolidated Balance Sheets: December 31, 2018 December 31, 2017 Post- Post- Defined Retirement Defined Retirement Benefit Benefits Total Benefit Benefits Total Prepaid post-retirement benefits $ — $ 341.4 $ 341.4 $ — $ — $ — Accounts payable and accrued liabilities (27.6) — (27.6) (0.6) — (0.6) Future employee obligations (273.9) (10.3) (284.2) (104.9) (19.6) (124.5) $ (301.5) $ 331.1 $ 29.6 $ (105.5) $ (19.6) $ (125.1) The funded status based on the accumulated benefit obligation for all defined benefit plans were: December 31, 2018 December 31, 2017 Canada United States Canada United States Accumulated benefit obligation (a) $ (32.9) $ (1,525.6) $ (143.9) $ (274.2) Fair value of plan assets 13.8 1,354.1 115.2 248.7 Funded status $ (19.1) $ (171.5) $ (28.7) $ (25.5) (a) Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels. The following amounts were not recognized in the net periodic benefit cost and recorded in the other comprehensive Income (losses): Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2018 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ (0.3) $ 0.4 $ (0.2) $ — $ (0.5) $ 0.4 Net actuarial loss (8.7) (0.5) (10.7) (5.0) (19.4) (5.5) Recognized in AOCI pre-tax $ (9.0) $ (0.1) $ (10.9) $ (5.0) $ (19.9) $ (5.1) Increase by the amount included in deferred tax liabilities 2.4 — 2.2 1.4 4.6 1.4 Net amount in AOCI after-tax $ (6.6) $ (0.1) $ (8.7) $ (3.6) $ (15.3) $ (3.7) Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2017 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ (0.4) $ — $ — $ — $ (0.4) $ — Net actuarial loss (13.9) (1.3) — — (13.9) (1.3) Recognized in AOCI pre-tax $ (14.3) $ (1.3) $ — $ — $ (14.3) $ (1.3) Increase (decrease) by the amount included in deferred tax liabilities 4.0 0.3 (0.1) — 3.9 0.3 Net amount in AOCI after-tax $ (10.3) $ (1.0) $ (0.1) $ — $ (10.4) $ (1.0) The following amounts were not recognized in the net periodic benefit cost and recorded in a regulatory asset (liability): Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2018 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ — $ — $ 0.8 $ (110.2) $ 0.8 $ (110.2) Net actuarial gain (loss) — — 188.2 (52.6) 188.2 (52.6) Recognized in regulatory asset (liability) $ — $ — $ 189.0 $ (162.8) $ 189.0 $ (162.8) Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2017 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ — $ — $ (1.2) $ 5.6 $ (1.2) $ 5.6 Net actuarial gain (loss) (30.6) 0.4 (74.0) (12.8) (104.6) (12.4) Recognized in regulatory asset (liability) $ (30.6) $ 0.4 $ (75.2) $ (7.2) $ (105.8) $ (6.8) The costs of the defined benefit and post-retirement benefit plans are based on Management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits. Post- Defined Retirement Amounts to be amortized in the next fiscal year from AOCI Benefit Benefits Past service costs $ 0.1 $ 0.2 Actuarial losses 0.5 — Total $ 0.6 $ 0.2 Post- Amounts to be amortized in the next fiscal year from regulatory Defined Retirement assets (liabilities) Benefit Benefits Past service costs $ 0.2 $ (21.3) Actuarial losses 9.1 0.1 Total $ 9.3 $ (21.2) The net pension expense by plan for the period was as follows: Year ended December 31, 2018 Canada United States Total Post- Post- Post- Defined retirement Defined retirement Defined retirement Benefit Benefits Benefit Benefits Benefit Benefits Current service cost (a) $ 2.4 $ 0.1 $ 16.2 $ 5.3 $ 18.6 $ 5.4 Interest cost (b) 1.2 0.1 38.0 10.9 39.2 11.0 Expected return on plan assets (b) (0.5) — (49.9) (21.6) (50.4) (21.6) Amortization of past service cost (b) 0.1 — — — 0.1 — Amortization of net actuarial loss (b) 0.6 — — — 0.6 — Amortization of regulatory asset (b) — — 7.8 (11.1) 7.8 (11.1) Net benefit cost (income) recognized $ 3.8 $ 0.2 $ 12.1 $ (16.5) $ 15.9 $ (16.3) (a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “Other Income” on the Consolidated Statements of Income. Year ended December 31, 2017 Canada United States Total Post- Post- Post- Defined retirement Defined retirement Defined retirement Benefit Benefits Benefit Benefits Benefit Benefits Current service cost (a) $ 7.9 $ 0.7 $ 8.0 $ 1.8 $ 15.9 $ 2.5 Interest cost (b) 5.8 0.6 11.7 2.9 17.5 3.5 Expected return on plan assets (b) (5.9) (0.2) (16.9) (4.7) (22.8) (4.9) Settlement of plan (b) — — — 0.2 — 0.2 Amortization of past service cost (b) 0.2 — — — 0.2 — Amortization of net actuarial loss (b) 0.7 — — — 0.7 — Amortization of regulatory asset/liability (b) 1.3 0.1 6.5 (0.3) 7.8 (0.2) Net benefit cost (income) recognized $ 10.0 $ 1.2 $ 9.3 $ (0.1) $ 19.3 $ 1.1 (a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “Other Income” on the Consolidated Statements of Income. The objective of the Corporation's investment policy is to maximize long - term total return while protecting the capital value of the fund from major market fluctuations through diversification and selection of investments. The objective for fund returns, over three to five -year periods, is the sum of two components - a passive component, which is the benchmark index market returns for the asset mix in effect, plus the added value expected from active management. It is the Corporation’s belief that the potential additional returns justify the additional risk associated with active management. The risk inherent in the investment strategy over a market cycle (a three - to five - year period) is two - fold. There is a risk that the market returns, as measured by the benchmark returns, will not be in line with expectations. The other risk is that the expected added value of active management over passive management will not be realized over the time period prescribed in each fund manager's mandate. There is also the risk of annual volatility in returns, which means that in any one year the actual return may be very different from the expected return. Cash and money market investments may be held from time to time as short - term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s). The Corporation has a target asset mix for the Canadian plans of 45 percent to 55 percent fixed income assets. The target asset mix for SEMCO plans is 33 percent fixed income assets and for WGL plans is 40 percent to 55 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk - reward tolerance of the Corporation. The collective investment mixes for the plans are as follows as at December 31, 2018 : Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 1.7 $ 1.7 $ — 12.3 Canadian equities 3.7 3.7 — 26.8 Foreign equities 2.1 2.1 — 15.2 Fixed income 5.5 5.5 — 39.9 Real estate 0.8 — 0.8 5.8 $ 13.8 $ 13.0 $ 0.8 100.0 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 6.3 $ 6.3 $ — 0.3 Canadian equities 2.1 2.1 — 0.1 Foreign equities (a) 273.2 270.6 2.6 12.7 Fixed income 850.1 99.2 750.9 39.6 Derivatives 9.3 — 9.3 0.4 Other 10.9 — 10.9 0.5 Total investments in the fair value hierarchy $ 1,151.9 378.2 773.7 53.6 Investments measured at net asset value using the NAV practical expedient (b) Commingled funds and pooled separate accounts (c) 945.3 44.2 Private Equity/Limited Partnership (d) 48.2 2.2 Total fair value of plan investments $ 2,145.4 100.0 Net payable (e) (0.1) — $ 2,145.3 100.0 (a) Investments in foreign equities include U.S. and international securities. (b) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (c) As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans. (d) At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies. (e) At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Total Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 8.0 $ 8.0 $ — 0.4 Canadian equities 5.8 5.8 — 0.3 Foreign equities (a) 275.3 272.7 2.6 12.8 Fixed income 855.6 104.7 750.9 39.6 Derivatives 9.3 — 9.3 0.4 Real estate 0.8 — — — Other 10.9 — 11.7 0.5 Total investments in the fair value hierarchy $ 1,165.7 $ 391.2 $ 774.5 54.0 Investments measured at net asset value using the NAV practical expedient (b) Commingled funds and pooled separate accounts (c) 945.3 43.8 Private Equity/Limited Partnership (d) 48.2 2.2 Total fair value of plan investments $ 2,159.2 100.0 Net payable (e) (0.1) — $ 2,159.1 100.0 (a) Investments in foreign equities include U.S. and international securities. (b) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (c) As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans. (d) At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies. (e) At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Post- Post- Significant actuarial assumptions used in measuring Defined Retirement Defined Retirement net benefit plan costs Benefit Benefits Benefit Benefits Year ended December 31 2018 2017 Discount rate (%) 3.25 - 4.30 3.60 - 4.30 2.65 - 4.20 4.00 - 4.20 Expected long-term rate of return on plan assets (%) (a) 3.20 - 7.60 3.75 - 7.60 6.18 - 7.30 3.10 - 7.30 Rate of compensation increase (%) 2.75 - 4.10 4.10 2.75 - 4.00 3.25 Average remaining service life of active employees (years) 9.6 14.1 12.7 13.5 (a) Only applicable for funded plans Post- Post- Significant actuarial assumptions used in measuring Defined Retirement Defined Retirement benefit obligations Benefit Benefits Benefit Benefits As at December 31 2018 2017 Discount rate (%) 3.60 - 4.40 3.90 - 4.50 2.80 - 3.70 3.60 - 3.70 Rate of compensation increase (%) 2.75 - 4.10 4.10 2.75 - 4.00 3.25 The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio. The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments. The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rates used to measure the expected cost of benefits for the next year were between 6.4 and 6.5 percent. The health care cost trend rates were assumed to decline to between 2.1 and 5 percent by 2024 . The assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage point change in the assumed health care trend rates would have the following effects for 2018: Increase Decrease Service and interest costs $ 1.7 $ (1.3) Accrued benefit obligation $ 19.8 $ (16.0) The following table shows the expected cash flows for defined benefit pension and other-post retirement plans: Post- Defined Retirement Benefit Benefits Expected employer contributions: 2019 $ 41.4 $ 0.1 Expected benefit payments: 2019 $ 109.8 $ 25.3 2020 92.2 24.6 2021 95.3 25.0 2022 101.0 25.4 2023 99.4 25.5 2024 - 2028 $ 521.9 $ 130.9 |
COMMITMENTS, CONTINGENCIES AND
COMMITMENTS, CONTINGENCIES AND GUARANTEES | 12 Months Ended |
Dec. 31, 2018 | |
COMMITMENTS, CONTINGENCIES AND GUARANTEES [Abstract] | |
COMMITMENTS, CONTINGENCIES AND GUARANTEES | 29. COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments AltaGas has long-term natural gas purchase and transportation arrangements, electricity purchase arrangements, service agreements, storage contracts, environmental commitments, and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business. In connection with the WGL Acquisition, AltaGas and WGL have made commitments related to the terms of the PSC of DC settlement agreement and the conditions of approval from the PSC of MD and the SCC of VA. Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. The total amount expensed in 2018 was approximately US$140 million, of which US$111 million has been paid as of December 31, 2018. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, investment of US$70 million over a 10 year period to further extend natural gas service, and US$8 million for leak mitigation. Future payments of these commitments at December 31, 2018 are estimated as follows: 2019 2020 2021 2022 2023 2024 and beyond Total Gas purchase (a) $ 3,157.1 $ 2,940.5 $ 2,639.3 $ 2,527.4 $ 2,349.9 $ 30,309.2 $ 43,923.4 Electricity purchase (c) 533.1 368.6 139.2 38.6 5.7 0.4 1,085.6 Service agreements (b)(d) 74.3 48.2 30.9 17.3 14.8 168.0 353.5 Pipeline and storage services (e) 861.6 862.2 818.8 795.6 781.7 4,645.3 8,765.2 Capital projects (f) 119.2 — — — — — 119.2 Operating leases (g) 23.9 30.9 29.4 28.0 25.8 164.8 302.8 Environmental (h) 6.1 4.7 3.0 0.5 0.4 0.5 15.2 Merger commitments 29.3 30.8 22.8 19.2 19.2 62.1 183.4 $ 4,804.6 $ 4,285.9 $ 3,683.4 $ 3,426.6 $ 3,197.5 $ 35,350.3 $ 54,748.3 (a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (b) In 2014, AltaGas' Blythe facility entered into a Long - Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hour per CT, or 25 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2018, the total commitment was $190.9 million payable over the next 16 years, of which $59.6 million is expected to be paid over the next five years. (c) AltaGas enters into contracts to purchase electricity from various suppliers for its utilities. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include $44.1 million of commitments related to renewable energy credits. (d) In 2017, AltaGas entered into a 12 -year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed and variable fees of approximately $60.1 million over the term of the contract. (e) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (f) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. (g) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, office and other equipment. (h) Environmental commitments relate to future costs associated with sites where AltaGas or its predecessors may have operated manufactured gas plants. Guarantees AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. AltaGas has also guaranteed payments for certain of its external partners. As at December 31, 2018, AltaGas has no guarantees to external parties. Contingencies AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations. As a result of the WGL Acquisition, AltaGas has the following additional contingencies: Antero Contract Washington Gas and WGL Midstream contracted in June 2014 with Antero Resources Corporation (Antero) to buy gas from Antero at invoiced prices based on an index, and at a delivery point, specified in the contracts. Since deliveries began, however, the index price paid has been more than the fair market value at the same physical delivery point, resulting in losses within WGL entities of approximately US $40 million. Accordingly, Washington Gas and WGL Midstream notified Antero that it sought to apply a provision of the contracts that would permit a new index to be established. Antero objected, claiming that the contract provisions permitting re-pricing did not apply, unless Antero itself chose to sell gas at cheaper prices at the delivery point (which Antero claimed it had not). The dispute was arbitrated in January 2017, and the arbitral tribunal ruled in favor of Antero on the applicability of the re-pricing mechanism. However, the tribunal ruled that it lacked authority to determine whether Antero was in breach of its obligation to deliver gas to Washington Gas and WGL Midstream at a point where they could obtain the higher pricing. Accordingly, Washington Gas and WGL Midstream filed suit in state court in Colorado for a determination of this issue. The state court initially granted Antero’s motion to dismiss the case and WGL subsequently filed an appeal. In October 2018, the Court of Appeals reversed the state court’s decision and remanded the lawsuit to the trial court. Separately, Antero has initiated suit against Washington Gas and WGL Midstream, claiming that they have failed to purchase specified daily quantities of gas and seeking alleged cover damages exceeding US$100 million as of April 4, 2018 according to Antero’s complaint. Washington Gas and WGL Midstream oppose both the validity and amount of Antero’s claim. WGL believes the probability that Antero could succeed in collecting these penalties is remote therefore no accrual was made as of December 31, 2018. In December 2017, WGL Midstream amended its purchase contract with Antero and, effective February 1, 2018, is no longer obligated to purchase gas at the delivery point that is the subject of these disputes. These two cases have been consolidated and a jury trial has been scheduled for June 10, 2019. Silver Spring, Maryland Incident Washington Gas has continually worked with the National Transportation and Safety Board (NTSB) to support its investigation of the August 2016 explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland, the cause of which has not been determined. Additional information will be made available by the NTSB at the appropriate time. A total of 40 civil actions related to the incident have been filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits seek unspecified damages for personal injury and/or property damage. The one class action suit filed against WGL and Washington Gas was amended to assert property damage and loss of use claims. WGL maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention and expects this coverage will be sufficient to cover any significant liability to it that may result from this incident. Management is unable to determine a range of potential losses that is reasonably possible of occurring and therefore has not recorded a reserve associated with this incident. Washington Gas was invited by the NTSB to be a party to the investig ation and in that capacity, continues to work closely with the NTSB . The NTSB has scheduled a hearing for April 23, 2019 to determine the probable cause of the incident. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2018 | |
RELATED PARTY TRANSACTIONS [Abstract] | |
RELATED PARTY TRANSACTIONS | 30. RELATED PARTY TRANSACTIONS In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows: As at December 31, 2018 December 31, 2017 Due from related parties Accounts receivable (a) $ 60.8 $ 0.8 Long-term investments and other assets (b) 45.0 75.0 $ 105.8 $ 75.8 Due to related parties Accounts payable (c) 6.3 3.2 Risk management liabilities - current (d) 0.9 — $ 7.2 $ 3.2 (a) Receivable s from joint ventures and ACI. (b) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021 . As at December 31, 2018, Petrogas had drawn $45.0 million (December 31, 2017 - $75.0 million) under the facility. (c) Payables to ACI and a joint venture . (d) Foreign exchange hedge with ACI. The following transactions with related parties have been recorded on the Consolidated Statements of Income for the year ended December 31, 2018 and 2017 : Year ended December 31 2018 2017 Revenue (a) $ 68.4 $ 15.0 Cost of sales (b) $ (4.2) $ (6.5) Operating and administrative expenses (c) $ 1.3 $ — Other income (d) $ 9.2 $ 4.4 (a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI . In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil ). (b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sa le of natural gas liquids to affiliate s . (c) Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive. (d) Interest income from loans to Petrogas (secured loan facility) and loans to ACI . Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2018 | |
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | 31. SUPPLEMENTAL CASH FLOW INFORMATION The following table details the changes in operating assets and liabilities from operating activities: Year ended December 31 2018 2017 Source (use) of cash: Accounts receivable $ (526.9) $ (55.6) Inventory (100.8) 4.7 Other current assets 12.5 7.0 Regulatory assets (current) (15.8) (0.2) Accounts payable and accrued liabilities 237.9 85.4 Customer deposits (13.3) (2.8) Regulatory liabilities (current) 69.2 (4.8) Other current liabilities (5.9) 13.0 Other operating assets and liabilities (143.4) (44.8) Changes in operating assets and liabilities $ (486.5) $ 1.9 The following cash payments have been included in the determination of earnings: Year ended December 31 2018 2017 Interest paid (net of capitalized interest) $ 288.9 $ 151.1 Income taxes paid $ 36.9 $ 36.3 The following table is a reconciliation of c ash and restricted cash balances: As at December 31 2018 2017 Cash and cash equivalents $ 101.6 $ 27.3 Restricted cash holdings from customers - current 4.1 8.9 Restricted cash holdings from customers - non-current 6.1 7.5 Restricted cash included in prepaid expenses and other current assets (a) 27.6 — Restricted cash included in long-term investments and other assets (a) 61.7 — Cash, cash equivalents and restricted cash per consolidated statement of cash flow $ 201.1 $ 43.7 (a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relates to Rabbi trusts associated with WGL’s pension plans (Note 28). On the date of the WGL Acquisition, the restricted cash balances related to Rabbi trusts was $81.0 million. |
SEGMENTED INFORMATION
SEGMENTED INFORMATION | 12 Months Ended |
Dec. 31, 2018 | |
SEGMENTED INFORMATION [Abstract] | |
SEGMENTED INFORMATION | 32. SEGMENTED INFORMATION AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end-user. The following describes the Corporation’s four reporting segments: Utilities – – – rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; rate-regulated natural gas storage in the United States; and equity investment in AltaGas Canada Inc. Midstream – NGL processing and extraction plants; – transmission pipelines to transport natural gas and NGL; – natural gas gathering lines and field processing facilities; – purchase and sale of natural gas ; – natural gas storage facilities; – – liquefied petroleum gas (LPG) terminal currently under construction; natural gas and NGL marketing; – equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents ; – interests in four regulated gas pipelines in the Marcellus/Utica basins; and – sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania. Power – natural gas - fired, biomass, and solar power generation assets, whereby outputs are generally sold under power purchase agreements, both operational and under development; – energy storage; and – sale of power to residential, commercial and industrial users in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania. Corporate – the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts . The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 23 : Year ended December 31, 2018 Utilities Midstream Power Corporate Total External revenue (note 23) $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5) $ 4,256.7 Intersegment revenue 13.0 90.4 9.0 0.1 112.5 Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4) $ 4,369.2 Geographic Information Year ended December 31 2018 2017 Revenue (a) Canada $ 1,626.8 $ 1,508.8 United States 2,553.0 1,109.9 Total $ 4,179.8 $ 2,618.7 (a) Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts. As at December 31 2018 2017 Property, plant and equipment Canada $ 2,348.2 $ 4,320.5 United States 8,581.4 2,369.3 Total $ 10,929.6 $ 6,689.8 The following tables show the composition by segment: Year ended December 31, 2018 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4) $ (112.5) $ 4,256.7 Cost of sales (838.3) (976.4) (743.7) — 103.1 (2,455.3) Operating and administrative (727.4) (201.7) (159.1) (50.6) 9.8 (1,129.0) Accretion expenses (0.1) (4.0) (6.8) — — (10.9) Depreciation and amortization (165.8) (84.4) (130.5) (13.3) — (394.0) Provisions on assets (note 10) (193.7) (153.7) (381.3) — — (728.7) Income from equity investments 7.2 51.1 (10.4) — — 47.9 Other income (loss) 4.5 0.7 (5.9) 2.0 (0.4) 0.9 Foreign exchange gains — (0.2) (0.1) 4.8 — 4.5 Interest expense (103.9) (10.6) (8.9) (185.6) — (309.0) Loss before income taxes $ (251.9) $ 55.8 $ (275.7) $ (245.1) $ — $ (716.9) Net additions (reductions) to: Property, plant and equipment (b) $ 507.0 $ 383.4 $ (321.9) $ 4.0 $ — $ 572.5 Intangible assets $ 21.8 $ 4.7 $ 12.5 $ 6.7 $ — $ 45.7 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets. Year ended December 31, 2017 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 1,126.7 $ 1,008.0 $ 631.7 $ (58.4) $ (151.8) $ 2,556.2 Cost of sales (610.1) (647.0) (242.8) — 142.8 (1,357.1) Operating and administrative (226.1) (165.0) (93.1) (97.5) 9.5 (572.2) Accretion expenses (0.1) (3.9) (6.9) — — (10.9) Depreciation and amortization (81.8) (68.6) (118.0) (14.0) — (282.4) Provision on assets — (6.6) (133.0) — — (139.6) Income from equity investments 2.6 22.0 6.8 — — 31.4 Other income (loss) 3.9 (0.9) 0.8 6.3 (0.5) 9.6 Foreign exchange gains — 0.2 — 1.5 — 1.7 Interest expense — — — (170.3) — (170.3) Income (loss) before income taxes $ 215.1 $ 138.2 $ 45.5 $ (332.4) $ — $ 66.4 Net additions (reductions) to: Property, plant and equipment (b) $ 124.3 $ 245.3 $ 16.5 $ 1.5 $ — $ 387.6 Intangible assets $ 2.1 $ 2.8 $ 13.2 $ 2.2 $ — $ 20.3 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets. The following table shows goodwill and total assets by segment: Utilities Midstream Power Corporate Total As at December 31, 2018 Goodwill $ 3,450.8 $ 426.4 $ 191.0 $ — $ 4,068.2 Segmented assets $ 12,991.3 $ 6,398.8 $ 3,814.7 $ 282.9 $ 23,487.7 As at December 31, 2017 Goodwill $ 664.7 $ 152.6 $ — $ — $ 817.3 Segmented assets $ 3,460.2 $ 3,096.8 $ 3,192.5 $ 282.7 $ 10,032.2 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2018 | |
SUBSEQUENT EVENTS [Abstract] | |
SUBSEQUENT EVENTS | 33 . SUBSEQUENT EVENTS Subsequent events have been reviewed through February 27, 2019, the date these Consolidated Financial Statements were issued . On January 31, 2019, AltaGas completed the sale of its remaining interest in the Northwest Hydro facilities for net proceeds of approximately $1.37 billion . On February 1, 2019, AltaGas completed the sale of non-core Midstream and Power assets in Canada. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |
BASIS OF PRESENTATION | BASIS OF PRESENTATION These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). Pursuant to National Instrument 52 - 107, "Acceptable Accounting Principles and Auditing Standards" (NI 52 - 107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP. |
PRINCIPLES OF CONSOLIDATION | PRINCIPLES OF CONSOLIDATION These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method. Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain WGL equity method investments as well as WGL consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage. All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non - controlling interest in a subsidiary that AltaGas controls, that non - controlling interest is reflected as “non - controlling interests” in the Consolidated Financial Statements. The non - controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non - controlling interests". |
USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY | USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods. |
Rate-Regulated Operations | Rate - Regulated Operations SEMCO Gas, ENSTAR, Washington Gas, and Hampshire (collectively Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD) and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively. The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months. |
Restricted Cash Holdings from Customers | Restricted Cash Holdings from Customers Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain WGL executive and outside director retirement benefit plan obligations. As of December 31, 2018, the rabbi trust funds are invested in money market funds which are considered as cash equivalents. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets. |
Accounts Receivable | Accounts Receivable Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. |
Inventory | Inventory Inventory consi sts of materials, supplies, natural gas, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas. |
Property, Plant and Equipment (PP&E), Depreciation and Amortization | Property, Plant, and Equipment (PP&E), Depreciation and Amortization Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight - line basis over the estimated useful life of the assets, with the exception of rate regulated utilities assets, where depreciation is calculated on a straight - line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities. The U.S. utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long - term interest rate. Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators. The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 3 - 80 years Midstream assets 3 - 45 years Power generation assets 2 - 120 years Corporate assets 1 - 20 years As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month they are brought into active service. Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income. Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases. |
Intangible Assets | Intangible Assets Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight - line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 -19 years Electricity service agreements 2 - 60 years Software 3 - 10 years Land rights 5 - 6 4 years Franchises and consents 9 - 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 years The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years. |
Assets Held for Sale | Assets Held for Sale The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized. |
Business Acquisitions | Business Acquisitions Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition - related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired. |
Provision on Assets | Provisions on Assets If facts and circumstances suggest that a long - lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized. Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statement of Income. |
Development Costs | Development Costs AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations. |
Investments Accounted for by the Equity Method | Investments Accounted for by the Equity Method The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period. The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period. An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income. |
Financial Instruments | Financial Instruments Non-Utility Operations All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held - for - trading", "held - to - maturity", or "loans and receivables". Financial liabilities are classified as "held - for - trading" or other financial liabilities. Subsequent measurement is determined by classification. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Held - for - trading instruments include non - derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under "other income". Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings. The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Transaction costs related to the acquisition of held - for - trading financial assets and liabilities are expensed as incurred. Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long - term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long - term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statement of Income. Regulated Utility Operations All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income. |
Weather-Related Instruments | Weather-Related Instruments WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 22 for further discussion on weather-related instruments . |
Hedges | Hedges As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815. Non-Utility Operations The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs. Regulated Utility Operations During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt. |
Asset Retirement Obligations | Asset Retirement Obligations AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations. There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates , as allowed by the regulators . These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980. Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators. |
Revenue Recognition | Revenue Recognition AltaGas has revenue from various sources, including rate regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 23. |
Foreign Currency Translation | Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non - monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date. For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI. AltaGas may designate some of its U.S. dollar denominated long - term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long - term debt are included in OCI. |
Share Options and Other Compensation Plans | Share Options and Other Compensation Plans Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity. AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common shares purchased from the market. The other portion of RU’s and PSUs are valued at US$1 per unit. Upon vesting, the RUs and PSUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation's performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs. |
Pension Plans and Post-Retirement Benefits | Pension Plans and Post - Retirement Benefits AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs. The cost of defined benefit pension plans and post - retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post - retirement benefit plans is 9.6 years and 14.1 years, respectively. AltaGas recognizes the overfunded or underfunded status of its pension and post - retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability. For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. |
Income Taxes | Income Taxes Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities. Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties. The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future. |
Net Income per Share | Net Income per Share Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share - based compensation awards. The potentially dilutive impact of the share - based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. |
Contingencies | Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change. |
ADOPTION OF NEW ACCOUNTING STANDARDS AND FUTURE CHANGES IN ACCOUNTING PRINCIPLES | ADOPTION OF NEW ACCOUNTING STANDARDS Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU): · ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”). AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 23 for further details. The application of ASC 606 did not have a material impact on AltaGas’ consolidated financial statements in 2018; · ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments ”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow . The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis; · ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively; · ASU No. 2017-04 “Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2017-05 “Other Income – Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2017-07 “Compensation – Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $1.6 million of net benefit cost associated with other components were reclassified from the line item “operating and administrative” to “other income” on the Consolidated Statements of Income for the year ended December 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2017-09 “Compensation – Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2017-12 “Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; · ASU No. 2018-02 “Income Statement – Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and · ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments – Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements. FUTURE CHANGES IN ACCOUNTING PRINCIPLES In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU 2018-01 “Land Easement Practical Expedient for Transition to Topic 842”, providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. In July 2018, FASB issued ASU 2018-11 “Targeted Improvements”, allowing entities to report the comparative periods presented in the period of adoption under the previous lease standard (ASC 840), and recognize a cumulative-effect adjustment to the opening balance of retained earnings as of January 1, 2019. The ASU also provides a practical expedient under which lessors are not required to separate out lease and non-lease components of a contract, provided certain conditions are met. In December 2018, FASB issued ASU 2018-20 “Narrow-Scope Improvement for Lessors”, allowing lessors to include and exclude certain costs from variable payments. The ASU also require lessors to allocate certain variable payments to the lease and non-lease components when the changes in facts and circumstances on which the variable payment is based occur. The amendments to the new lease standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. AltaGas is in the final stages of evaluating the impact of adopting ASC 842 on its consolidated financial statements. Leases, except as noted below, for which AltaGas is the lessee will be reflected on the balance sheet upon adoption by recording an increase to long-term assets and an increase to long-term liabilities net of the current portion that is recorded in current liabilities. The increases are expected to be less than 1 percent of total assets. AltaGas will utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842, as well as the transition practical expedients related to land easements and not separating out lease and non-lease components of a contract for certain classes of assets. As a result of the transition practical expedients, AltaGas expects to have primarily operating leases on transition consistent with its current conclusions under ASC 840. AltaGas will also elect to exclude leases with terms of 12 months or less from the calculation of lease liabilities and right of use assets under the short term lease exemption. In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements. In June 2018, FASB issued ASU No. 2018-07 “Compensation – Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In June 2018, FASB issued ASU No. 2018-08 “Not-for-Profit-Entities – Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this Update clarify whether a transfer of assets is a contribution or an exchange transaction. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement – Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In August 2018, FASB issued ASU No. 2018-14 “Compensation – Retirement Benefits-Defined Benefit Plans – General: Disclosure Framework – Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other postretirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In August 2018, FASB issued ASU No. 2018-15 “Intangibles – Goodwill and Other – Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted and AltaGas will early adopt this ASU on January 1, 2019. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In October 2018, FASB issued ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The amendments in this update should be adopted concurrently with ASU 2017-12. AltaGas early adopted ASU 2017-12 on January 1, 2018 and therefore will adopt this update on January 1, 2019. An entity should apply the amendments prospectively for any qualifying new or re-designated cash flow hedging relationships. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements. In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this Update provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. AN entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |
Summary of Estimated Useful Lives of Property, Plant and Equipment | Utilities assets 3 - 80 years Midstream assets 3 - 45 years Power generation assets 2 - 120 years Corporate assets 1 - 20 years |
Summary of Estimated Useful Lives of Finite-Lived Intangible Assets | Energy services relationships 5 -19 years Electricity service agreements 2 - 60 years Software 3 - 10 years Land rights 5 - 6 4 years Franchises and consents 9 - 25 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 years |
ACQUISITION OF WGL HOLDINGS I_2
ACQUISITION OF WGL HOLDINGS INC. (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
ACQUISITION OF WGL HOLDINGS INC. [Abstract] | |
Schedule of Final Purchase Price Allocation | Purchase consideration $ 5,973 Fair value assigned to net assets Current assets $ 1,187 Property, plant and equipment 5,943 Intangible assets 637 Regulatory assets 402 Long-term investments 1,411 Other long-term assets 449 Current liabilities (1,798) Long-term debt (2,548) Preferred shares (41) Regulatory liabilities (1,125) Deferred income taxes (772) Other long-term liabilities (959) Non-controlling interest (9) Fair value of net assets acquired $ 2,777 Goodwill $ 3,196 |
Summary of Pro Forma Information | Year ended December 31 2018 2017 Pro forma revenue $ 5,962 $ 5,704 Pro forma net income (loss) after taxes $ (304) $ 450 |
ASSETS HELD FOR SALE (Tables)
ASSETS HELD FOR SALE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS AND ASSETS HELD FOR SALE [Abstract] | |
Schedule of Assets Held for Sale | As at December 31, 2018 December 31, 2017 Assets held for sale Cash $ 4.9 $ — Accounts receivable 85.2 0.3 Inventory 0.5 — Property, plant and equipment 1,189.6 5.3 Intangible assets 248.7 0.1 Goodwill — 0.3 $ 1,528.9 $ 6.0 Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ 23.8 $ — Asset retirement obligations 10.8 0.3 Other long-term liabilities 136.8 — $ 171.4 $ 0.3 |
INVENTORY (Tables)
INVENTORY (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
INVENTORY [Abstract] | |
Schedule of Inventory | December 31, December 31, As at 2018 2017 Natural gas held in storage $ 418.0 $ 133.9 Materials and supplies 53.3 32.3 Renewable energy credits and emission compliance instruments 38.2 28.4 Other inventory 6.4 6.5 $ 515.9 $ 201.1 |
PROPERTY, PLANT AND EQUIPMENT (
PROPERTY, PLANT AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
PROPERTY, PLANT AND EQUIPMENT [Abstract] | |
Schedule of Property, Plant and Equipment | As at December 31, 2018 December 31, 2017 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 7,090.5 $ (89.7) $ 7,000.8 $ 2,245.4 $ (226.1) 2,019.3 Midstream 3,178.2 (845.7) 2,332.5 2,801.4 (636.3) $ 2,165.1 Power 4,633.9 (1,858.3) 2,775.6 2,874.8 (392.3) 2,482.5 Corporate 49.4 (39.1) 10.3 65.9 (37.7) 28.2 Reclassified to assets held for sale (note 5) (2,999.3) 1,809.7 (1,189.6) (16.7) 11.4 (5.3) $ 11,952.7 $ (1,023.1) $ 10,929.6 $ 7,970.8 $ (1,281.0) $ 6,689.8 |
INTANGIBLE ASSETS (Tables)
INTANGIBLE ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
Summary of Intangible Assets | As at December 31, 2018 December 31, 2017 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value E&T contracts $ 26.6 $ (14.3) $ 12.3 $ 26.6 $ (13.4) $ 13.2 Electricity service agreements 269.5 (25.9) 243.6 603.1 (108.5) 494.6 Energy services relationships 176.1 (33.8) 142.3 10.2 (8.1) 2.1 Software 293.9 (77.7) 216.2 126.8 (61.6) 65.2 Land rights 1.4 (0.2) 1.2 11.0 (2.4) 8.6 Commodity contracts 346.3 (6.3) 340.0 — — — Franchises and consents 5.0 — 5.0 7.4 (2.2) 5.2 Reclassified to assets held for sale (note 5) (277.4) 28.7 (248.7) (0.1) — (0.1) $ 841.4 $ (129.5) $ 711.9 $ 785.0 $ (196.2) $ 588.8 |
Summary of Estimated Amortization Expense of Intangible Assets | 2019 $ 84.2 2020 $ 82.5 2021 $ 57.6 2022 $ 132.3 2023 $ 38.3 Thereafter $ 120.6 |
GOODWILL (Tables)
GOODWILL (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
Schedule of Goodwill | December 31, December 31, As at 2018 2017 Balance, beginning of year $ 817.3 $ 856.0 Provisions on assets (notes 5 and 10) (124.2) — Business acquisition (note 3) 3,196.4 — Foreign exchange translation 178.7 (38.4) Reclassified to assets held for sale — (0.3) Balance, end of year $ 4,068.2 $ 817.3 |
PROVISIONS ON ASSETS (Tables)
PROVISIONS ON ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
Schedule of Provisions on Assets | Year ended December 31 2018 2017 Utilities $ 193.7 $ — Midstream 153.7 6.6 Power 381.3 133.0 $ 728.7 $ 139.6 |
LONG-TERM INVESTMENTS AND OTH_2
LONG-TERM INVESTMENTS AND OTHER ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
LONG-TERM INVESTMENTS AND OTHER ASSETS [Abstract] | |
Schedule of Long-Term and Other Investments | As at December 31, 2018 December 31, 2017 Investments in publicly-traded entities $ 8.4 $ 95.0 Loan to affiliate (note 30) 45.0 75.0 Deferred lease receivable 24.4 29.0 Debt issuance costs associated with credit facilities 7.9 20.3 Refundable deposits 16.2 14.9 Prepayment on long-term service agreements 82.5 68.1 Subscription receipts issuance costs — 1.7 Contract asset (note 23) 11.5 — Rabbi trust (note 28) 61.7 — Other 25.5 8.6 $ 283.1 $ 312.6 |
VARIABLE INTEREST ENTITIES (Tab
VARIABLE INTEREST ENTITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
VARIABLE INTEREST ENTITIES [Abstract] | |
Schedule of VIE Amounts in Consolidated Balance Sheets | As at December 31, December 31, 2018 2017 Current assets $ 1,383.5 $ 1.4 Property, plant and equipment 619.2 84.3 Long-term investments and other assets 48.0 48.0 Current liabilities (161.8) — Asset retirement obligations (0.9) — Deferred tax credits (3.0) — Net assets $ 1,885.0 $ 133.7 |
INVESTMENTS ACCOUNTED FOR BY TH
INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD [Abstract] | |
Schedule of Equity Method Investments | Carrying value as at December 31 Equity income (loss) for the year ended December 31 Description Location Ownership Percentage 2018 2017 2018 2017 AltaGas Canada Inc. (ACI) Canada 36.75 $ 112.5 $ — $ 5.4 $ — AltaGas Idemitsu Joint Venture LP (AIJVLP) Canada 50 342.9 323.3 2.1 6.6 Constitution Pipeline, LLC (Constitution) United States 10 — — (0.2) — Craven County Wood Energy LP United States 50 7.8 20.9 (14.1) 3.3 Eaton Rapids Gas Storage System United States 50 29.4 26.4 2.0 2.5 Grayling Generating Station LP United States 50 29.0 27.6 3.6 3.5 Inuvik Gas Ltd. (a) Canada 33.333 — — (0.2) — Meade Pipeline Co. LLC (Meade) (b) United States 55 757.8 — 12.2 — Mountain Valley Pipeline, LLC (Mountain Valley) United States 10 532.5 — 11.5 — Sarnia Airport Storage Pool LP Canada 50 18.7 18.8 1.0 1.0 Petrogas Preferred Shares Canada n/a 150.0 150.0 12.8 12.8 Tidewater Midstream and Infrastructure Ltd. (c) Canada n/a — — — 1.7 Stonewall Gas Gathering Systems LLC United States 30 411.8 — 11.8 — $ 2,392.4 $ 567.0 $ 47.9 $ 31.4 (a) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018. (b) Meade is a VIE (Note 12). (c) AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. in September 2018 (Note 11). |
Schedule of Combined Financial Information of Equity Method Investments | Year ended December 31 2018 2017 Revenues $ 351.6 $ 110.6 Expenses (142.7) (74.2) $ 208.9 $ 36.4 As at December 31 2018 2017 Current assets $ 1,204.6 $ 24.8 Property, plant and equipment $ 7,602.5 $ 82.8 Intangible assets $ 22.9 $ 5.6 Long-term investments and other assets $ 1,326.6 $ 843.3 Current liabilities $ (1,015.2) $ (41.7) Other long-term liabilities $ (949.6) $ (189.1) |
SHORT-TERM DEBT (Tables)
SHORT-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SHORT-TERM AND LONG-TERM DEBT [Abstract] | |
Schedule of Short-Term Debt | As at December 31, 2018 December 31, 2017 Bank indebtedness (a) $ 0.2 $ 6.2 US$150 million operating facility (b) — 31.7 $25 million operating facility (c) — 8.9 Commercial paper (d) 1,145.2 — Project financing 64.5 — $ 1,209.9 $ 46.8 (a) Bank indebtedness bears interest at the lender's prime rate or at the interest rate applicable to bankers' acceptances. The prime lending rate at December 31, 2018 was 3.95 percent ( December 31, 2017 – 3.2 percent). (b) As at December 31, 2018 , SEMCO held a US$1 50 million ( December 31, 2017 - US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 20, 202 3 . Draws on the facility can be by way of U.S. base - rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2018 were $0.7 million ( December 31, 2017 - $0.6 million). (c) Upon completion of the ACI IPO , the operating facility was transferred to ACI. (d) WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position . |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SHORT-TERM AND LONG-TERM DEBT [Abstract] | |
Schedule of Long-Term Debt | December 31, December 31, As at Maturity date 2018 2017 Credit facilities $1,400 million unsecured extendible revolving (a) 15-May-2023 $ 964.7 $ 219.1 US$300 million unsecured extendible revolving (b) 15-May-2022 287.8 — Acquisition credit facility 6-Jan-2020 113.2 — US $1,200 million revolving credit facility (g) 28-Dec-2021 1,637.0 — Medium-term notes (MTNs) $175 million Senior unsecured - 4.60 percent 15-Jan-2018 — 175.0 $200 million Senior unsecured - 4.55 percent 17-Jan-2019 200.0 200.0 $200 million Senior unsecured - 4.07 percent 1-Jun-2020 200.0 200.0 $350 million Senior unsecured - 3.72 percent 28-Sep-2021 350.0 350.0 $300 million Senior unsecured - 3.57 percent 12-Jun-2023 300.0 300.0 $200 million Senior unsecured - 4.40 percent 15-Mar-2024 200.0 200.0 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 299.9 299.9 $100 million Senior unsecured - 5.16 percent 13-Jan-2044 100.0 100.0 $300 million Senior unsecured - 4.50 percent 15-Aug-2044 299.8 299.8 $350 million Senior unsecured - 4.12 percent 7-Apr-2026 349.8 349.8 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 199.9 199.9 $250 million Senior unsecured - 4.99 percent 4-Oct-2047 250.0 250.0 WGL and Washington Gas medium-term notes US $500 million Senior unsecured - 2.25 to 4.76 percent Jan - Nov 2019 682.1 — US $250 million Senior unsecured - 2.88 percent 12-Mar-2020 341.1 — US $20 million Senior unsecured - 6.65 percent 20-Mar-2023 27.3 — US $40.5 million Senior unsecured - 5.44 percent 11-Aug-2025 55.3 — US $53 million Senior unsecured - 6.62 to 6.82 percent Oct - 2026 72.3 — US $72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 98.2 — US $52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 70.9 — US $8.5 million Senior unsecured - 7.50 percent 1-Apr-2030 11.6 — US $50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 68.2 — US $75 million Senior unsecured - 5.21 percent 3-Dec-2040 102.3 — US $75 million Senior unsecured - 5.00 percent 15-Dec-2043 102.3 — US $300 million Senior unsecured - 4.22 to 4.60 percent Sep - Dec 2044 409.3 — US $450 million Senior unsecured - 3.80 percent 15-Sep-2046 613.9 — SEMCO long-term debt US$300 million SEMCO Senior secured - 5.15 percent (d) 21-Apr-2020 409.3 376.4 US$82 million CINGSA Senior secured - 4.48 percent (e) 2-Mar-2032 86.3 85.2 Debenture notes PNG 2018 Series Debenture - 8.75 percent (c)(f) 15-Nov-2018 — 7.0 PNG 2025 Series Debenture - 9.30 percent (c)(f) 18-Jul-2025 — 13.0 PNG 2027 Series Debenture - 6.90 percent (c)(f) 2-Dec-2027 — 14.0 CINGSA capital lease - 3.50 percent 1-May-2040 0.6 0.5 CINGSA capital lease - 4.48 percent 4-Jun-2068 0.2 0.2 Fair value adjustment on WGL Acquisition (note 3) 89.0 — $ 8,992.3 $ 3,639.8 Less debt issuance costs (35.2) (14.4) 8,957.1 3,625.4 Less current portion (890.2) (188.9) $ 8,066.9 $ 3,436.5 (a) Borrowings on the facility can be by way of prime loans, U.S. base - rate loans, LIBOR loans, bankers' acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made. (b) Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, LIBOR loans , or letters of credit. (c) Collateral for the Secured Debentures and secured extendible revolving credit facility consisted of a specific first mortgage on substantially all of PNG's property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings. (d) Collateral for the US$ MTNs is certain SEMCO assets. (e) Collateral for the CINGSA Senior secured loan is certain CINGSA assets, Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan. (f) PNG debentures totaling $33.3 million have been sold to ACI (Note 4 ) Borrowings on the facility can be by way of U.S. base rate loans, U.S . prime loans, or LIBOR loans. |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
ASSET RETIREMENT OBLIGATIONS [Abstract] | |
Schedule of Changes in Asset Retirement Obligations | As at December 31, 2018 December 31, 2017 Balance, beginning of year $ 88.3 $ 81.6 Obligations acquired (note 3) 399.1 — New obligations 3.3 1.5 Obligations settled (4.2) (4.0) Disposals (1.6) — Revision in estimated cash flow 3.8 6.0 Accretion expense (a) 12.3 4.4 Foreign exchange translation 20.3 (0.9) Reclassified to liabilities associated with assets held for sale (note 5) (10.8) (0.3) Total 510.5 88.3 Less current portion (included in accounts payable and accrued liabilities) (9.9) — Balance, end of year $ 500.6 $ 88.3 (a) The majority of accretion expense is recorded through the Consolidated Statement of Income. Certain amounts relating to Washington Gas’ Utility asset retirement obligations are recorded through regulatory liabilities on the Consolidated Balance Sheets due to regulatory treatment. |
OTHER LONG-TERM LIABILITIES (Ta
OTHER LONG-TERM LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
OTHER LONG-TERM LIABILITIES [Abstract] | |
Schedule of Other Long-Term Liabilities | As at December 31, 2018 December 31, 2017 Deferred lease payable $ 13.1 $ 2.4 Deferred revenue 3.9 3.8 Customer advances for construction 58.6 40.9 Sundance B PPA termination expense (a) 2.0 4.0 NTL liability (b) — 142.0 Lease inducement 2.7 3.1 Merger commitments 21.4 — Other long-term liabilities 20.3 5.7 $ 122.0 $ 201.9 (a) On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”. (b) The NTL liability has been reclassified as liabilities associated with assets held for sale (Note 5). |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
INCOME TAXES [Abstract] | |
Schedule of Income Tax Provision | Year ended December 31 2018 2017 Income (loss) before income taxes - consolidated $ (716.9) $ 66.4 Statutory income tax rate (%) 27.0 27.0 Expected taxes at statutory rates $ (193.6) $ 17.9 Add (deduct) the tax effect of: Permanent differences (1.0) 9.5 Statutory and other rate differences (19.6) (30.5) Rate adjustment for change in tax rates 1.3 (34.1) Deferred income tax recovery on regulated assets (7.3) (7.4) Tax differences on divestitures and transactions (32.3) 6.9 Non-controlling interests 4.7 — Change in valuation allowance (22.3) 4.2 Other 6.9 — $ (263.2) $ (33.5) Income tax provision Current Canada 23.7 18.0 United States 0.7 12.5 $ 24.4 $ 30.5 Deferred Canada (166.1) (7.4) United States (121.5) (56.6) $ (287.6) $ (64.0) Effective income tax rate (%) 36.7 (50.5) |
Schedule of Deferred Income Tax Liabilities | As at December 31, 2018 December 31, 2017 PP&E and intangible assets $ 1,764.6 $ 726.5 Regulatory assets (166.3) 22.8 Tax pools, deferred financing and compensation (453.6) (302.3) Other (209.9) (59.3) Valuation allowance 23.1 53.7 $ 957.9 $ 441.4 |
Schedule of Uncertain Tax Positions | Year ended December 31 2018 2017 Balance, beginning of year $ 5.9 $ 2.2 Net changes during the year (3.7) 3.7 Balance, end of year $ 2.2 $ 5.9 |
REGULATORY ASSETS AND LIABILI_2
REGULATORY ASSETS AND LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
REGULATORY ASSETS AND LIABILITIES [Abstract] | |
Schedule of Regulatory Assets and Liabilities | As at December 31, 2018 December 31, 2017 Recovery Period Regulatory assets - current Deferred cost of gas (a) $ 20.4 $ 0.5 Less than one year Deferred property taxes — 0.3 Less than one year Other 0.6 0.3 Less than one year $ 21.0 $ 1.1 Regulatory assets - non-current Deferred regulatory costs and rate stabilization adjustment mechanism (a)(b) $ 215.5 $ 20.5 1 - 3 years Pipeline rehabilitation costs — 0.3 Various Future recovery of pension and other retirement benefits (a) 192.9 113.9 Various Future recovery of non-retirement employee benefits (a)(c) 21.3 — Various Deferred pension costs (d) 7.8 — 1 years Deferred environmental costs (a)(e) 19.9 13.9 1 - 10 years Deferred loss on reacquired debt (a)(f) 109.3 2.5 1 - 15 years Deferred depreciation and amortization — 23.3 Various Deferred future income taxes (a)(g) 67.0 104.7 Various Deferred customer retention program amortization — 16.5 Various Revenue deficiency account — 31.0 Various Other 29.3 2.0 Various $ 663.0 $ 328.6 Regulatory liabilities - current Deferred cost of gas $ 71.2 $ 9.0 Less than one year Refundable tax credit (h) 3.8 1.9 Less than one year Federal income tax rate change (i) 26.2 — Less than one year Other 13.7 — Less than one year $ 114.9 $ 10.9 Regulatory liabilities - non-current Option fees deferral (a) $ — $ 4.3 Various Refundable tax credit (h) 6.1 7.5 Various Future expense of pension and other retirement benefits (a) 166.7 — Various Future removal and site restoration costs (j) 514.7 153.3 3 - 56 years Deferred loss on reacquired debt 1.8 — Various Federal income tax rate change (a)(i) 698.4 101.8 Various Insurance recovery of environmental costs — 0.3 2 years Other 5.1 1.4 Various $ 1,392.8 $ 268.6 (a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions. (b) Includes fair value of derivatives, which are not included in customer bills until settled. (c) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator. (d) Relates to cos ts not recoverable through rates in the District of Columbia jurisdiction. However, Washington Ga s is allowed to amortize these prior unrecovered pension and other post-retirement benefits through 2019 . (e) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates. (f) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. This also includes a fair value adjustment of $89 million recorded on the WGL Acquisition (Note 3). (g) This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates. (h) On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology. (i) The TCJA was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers. This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment |
ACCUMULATED OTHER COMPREHENSI_2
ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
ACCUMULATED OTHER COMPREHENSIVE INCOME [Abstract] | |
Schedule of Accumulated Other Comprehensive Income | ($ millions) Available- for-sale Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Equity investee Total Opening balance, January 1, 2018 $ (7.1) $ (11.4) $ (129.0) $ 342.9 $ 3.7 $ 199.1 OCI before reclassification — (14.1) (90.6) 458.5 2.1 355.9 Amounts reclassified from OCI — 0.7 — — — 0.7 Adoption of ASU No. 2016-01 (note 2) 7.1 — — — — 7.1 Curtailment of DB and PRB plan — 4.2 — — — 4.2 Current period OCI (pre-tax) 7.1 (9.2) (90.6) 458.5 2.1 367.9 Income tax on amounts retained in AOCI — 3.3 10.4 — — 13.7 Income tax on amounts reclassified to earnings — (0.2) — — — (0.2) Income tax on amounts related to curtailment of DB and PRB plan — (1.5) — — — (1.5) Net current period OCI 7.1 (7.6) (80.2) 458.5 2.1 379.9 Ending balance, December 31, 2018 $ — $ (19.0) $ (209.2) $ 801.4 $ 5.8 $ 579.0 Opening balance, January 1, 2017 $ 19.8 $ (11.3) $ (135.6) $ 526.3 $ 5.9 $ 405.1 OCI before reclassification (30.3) (1.3) 6.6 (183.4) (2.2) (210.6) Amounts reclassified from AOCI — 1.3 — — — 1.3 Current period OCI (pre-tax) (30.3) — 6.6 (183.4) (2.2) (209.3) Income tax on amounts retained in AOCI 3.4 0.3 — — — 3.7 Income tax on amounts reclassified to earnings — (0.4) — — — (0.4) Net current period OCI (26.9) (0.1) 6.6 (183.4) (2.2) (206.0) Ending balance, December 31, 2017 $ (7.1) $ (11.4) $ (129.0) $ 342.9 $ 3.7 $ 199.1 |
Summary of Reclassification from Accumulated Other Comprehensive Income | AOCI components reclassified Income statement line item Year ended December 31, 2018 Year ended December 31, 2017 Defined benefit pension and PRB plans Operating and administrative expense $ 0.7 $ 1.3 Deferred income taxes Income tax expenses – deferred (0.2) (0.4) $ 0.5 $ 0.9 |
FINANCIAL INSTRUMENTS AND FIN_2
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative [Line Items] | |
Schedule of Fair Value of Risk Management Assets and Liabilities | December 31, 2018 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 99.0 $ — $ 68.3 $ 30.7 $ 99.0 Risk management assets - non-current 49.0 — 18.0 31.0 49.0 Equity securities (b) 8.4 8.4 — — 8.4 Fair value through regulatory assets/liabilities (a) Risk management assets - current 15.1 — 2.7 12.4 15.1 Risk management assets - non-current 8.7 — — 8.7 8.7 Amortized cost Loans and receivables (b) 45.0 — 45.2 — 45.2 $ 225.2 $ 8.4 $ 134.2 $ 82.8 $ 225.4 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 72.0 $ — $ 41.3 $ 30.7 $ 72.0 Risk management liabilities - non-current 103.4 — 15.3 88.1 103.4 Fair value through regulatory assets/liabilities (a) Risk management liabilities - current 17.3 — 2.9 14.4 17.3 Risk management liabilities - non-current 109.6 — 0.1 109.5 109.6 Amortized cost Current portion of long-term debt 890.2 — 884.4 — 884.4 Long-term debt 8,066.9 — 6,027.6 2,012.7 8,040.3 Other current liabilities (c) 11.2 — 11.2 — 11.2 Other long-term liabilities (c) 2.0 — 2.0 — 2.0 $ 9,272.6 $ — $ 6,984.8 $ 2,255.4 $ 9,240.2 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non - financial liabilities. December 31, 2017 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income Risk management assets - current $ 38.6 $ — $ 38.6 $ — $ 38.6 Risk management assets - non-current 15.9 — 15.9 — 15.9 Equity securities (a) 95.0 95.0 — — 95.0 Amortized cost Loans and receivables (a) 75.0 — 85.6 — 85.6 $ 224.5 $ 95.0 $ 140.1 $ — $ 235.1 Financial liabilities Fair value through net income Risk management liabilities - current $ 57.6 $ — $ 57.6 $ — $ 57.6 Risk management liabilities - non-current 13.8 — 13.8 — 13.8 Amortized cost Current portion of long-term debt 188.9 — 189.6 — 189.6 Long-term debt 3,436.5 — 3,568.3 — 3,568.3 Other current liabilities (b) 22.4 — 22.4 — 22.4 Other long-term liabilities (b) 146.0 — 147.7 — 147.7 $ 3,865.2 $ — $ 3,999.4 $ — $ 3,999.4 (a) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (b) Excludes non - financial liabilities. |
Quantitative Information About The Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3 | Net Fair Value Valuation Technique Unobservable Inputs Range Natural gas $ (144.1) Discounted Cash Flow Natural Gas Basis Price (per dekatherm) ( $1.40 ) - $7.28 Natural gas $ (4.4) Option Model Natural Gas Basis Price (per dekatherm) ( $1.37 ) - $5.07 Annualized Volatility of Spot Market Natural Gas 37.46% - 900.98% Electricity $ (14.7) Discounted Cash Flow Electricity Congestion Price (per megawatt hour) ( $8.28 ) - $84.44 |
Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3 | For the year ended December 31 2018 2017 Natural Gas Electricity Total Natural Gas Electricity Total Balance, beginning of year $ — $ — $ — $ — $ — $ — Acquired (note 3) (136.1) (10.6) (146.7) — — — Realized and unrealized losses: — — — Recorded in income (8.3) (6.5) (14.8) Recorded in regulatory assets (5.9) — (5.9) — — — Transfers out of Level 3 7.3 — 7.3 — — — Purchases — 6.4 6.4 — — — Settlements 0.3 (3.4) (3.1) — — — Foreign exchange translation (5.8) (0.6) (6.4) Balance, end of year $ (148.5) $ (14.7) $ (163.2) $ — $ — $ — |
Realized And Unrealized Losses Recorded To Income For Level 3 Measurements | For the year ended December 31 2018 2017 Recorded to revenue Commodity contracts $ (11.1) $ — Recorded to cost of sales Commodity contracts (3.7) — $ (14.8) $ — |
Summary of Unrealized Gains (Losses) on Risk Management Contracts | For the year ended December 31 2018 2017 Natural gas $ (2.2) $ 2.2 Storage optimization — 2.7 NGL frac spread 40.0 (11.7) Power 9.3 (20.8) Foreign exchange 33.7 (34.9) $ 80.8 $ (62.5) |
Schedule of Offsetting Assets and Liabilities | December 31, 2018 Risk management assets (a) Gross amounts of recognized assets/liabilities Gross amounts offset in balance sheet Netting of collateral Net amounts presented in balance sheet Natural gas $ 200.8 $ (82.0) $ — $ 118.8 NGL frac spread 18.7 (0.7) — 18.0 Power 42.8 (7.8) — 35.0 $ 262.3 $ (90.5) $ — $ 171.8 Risk management liabilities (b) Natural gas $ 340.4 $ (82.0) $ (3.3) $ 255.1 NGL frac spread 2.7 (0.7) — 2.0 Power 50.6 (7.8) 1.2 44.0 Foreign exchange 1.2 — — 1.2 $ 394.9 $ (90.5) $ (2.1) $ 302.3 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non - current) balance of $57.7 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non - current) balance of $213.0 million. December 31, 2017 Risk management assets (a) Gross amounts of recognized assets/liabilities Gross amounts offset in balance sheet Netting of collateral Net amounts presented in balance sheet Natural gas $ 41.0 $ (6.2) $ — $ 34.8 NGL frac spread 1.3 (0.3) — 1.0 Power 17.7 (0.7) — 17.0 Foreign exchange 1.7 — — 1.7 $ 61.7 $ (7.2) $ — $ 54.5 Risk management liabilities (b) Natural gas $ 35.1 $ (6.2) $ — $ 28.9 NGL frac spread 25.3 (0.3) — 25.0 Power 14.0 (0.7) 4.2 17.5 $ 74.4 $ (7.2) $ 4.2 $ 71.4 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non - current) balance of $15.9 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $ 57.6 million and risk management liabilities (non - current) balance of $13.8 million. Cash Collateral The following table presents collateral not offset against risk management assets and liabilities: December 31, 2018 December 31, 2017 Collateral posted with counterparties $ 27.6 $ — Cash collateral held representing an obligation $ 0.8 $ — Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets. Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2018 and 2017, AltaGas had not posted any collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if the most intrusive credit-risk-related contingent features underlying these agreements were triggered: December 31, 2018 December 31, 2017 Risk management liabilities with credit-risk-contingent features $ 14.7 $ — Maximum potential collateral requirements $ 7.5 $ — |
Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives | Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) Alberta power price $1/MWh 0.3 PJM power price $1/MWh 1.2 AECO natural gas price $0.50/GJ 5.9 NYMEX natural gas price $0.50/GJ 31.5 NGL frac spread: Propane $1/Bbl 1.7 Butane $1/Bbl 0.1 Western Texas Intermediate (WTI) crude oil $1/Bbl 0.3 Natural gas $0.50/GJ 4.7 |
Schedule of Accounts Receivable Past Due or Impaired | As at December 31, 2018 Total AR accruals Receivables impaired Less than 30 days 31 to 60 days 61 to 90 days Over 90 days Trade receivable $ 1,574.6 $ 447.5 $ 54.7 $ 961.5 $ 74.1 $ 12.8 $ 24.0 Other 27.6 — — 27.5 — — 0.1 Allowance for credit losses (54.7) — (54.7) — — — — $ 1,547.5 $ 447.5 $ — $ 989.0 $ 74.1 $ 12.8 $ 24.1 As at December 31, 2017 Total AR accruals Receivables impaired Less than 30 days 31 to 60 days 61 to 90 days Over 90 days Trade receivable $ 383.0 $ 184.6 $ 2.4 $ 187.0 $ 7.9 $ 1.4 $ (0.3) Other 2.3 — — 2.3 — — — Allowance for credit losses (2.4) — (2.4) — — — — $ 382.9 $ 184.6 $ — $ 189.3 $ 7.9 $ 1.4 $ (0.3) Allowance for credit losses December 31, 2018 December 31, 2017 Balance, beginning of year $ 2.4 $ 2.5 Foreign exchange translation 0.1 (0.1) New allowance (a) 53.1 0.4 Change in allowance (0.9) — Allowance applied to uncollectible customer accounts — (0.4) Balance, end of year $ 54.7 $ 2.4 |
Schedule of Contractual Maturities for Financial Liabilities | Contractual maturities by period As at December 31, 2018 Total Less than 1 year 1-3 years 4-5 years After 5 years Accounts payable and accrued liabilities $ 1,488.2 $ 1,488.2 $ — $ — $ — Dividends payable 22.0 22.0 — — — Short-term debt 1,209.9 1,209.9 — — — Other current liabilities (a) 11.2 11.2 — — — Other long-term liabilities (a) 2.0 — 2.0 — — Risk management contract liabilities 302.3 89.3 113.3 33.3 66.4 Current portion of long-term debt (b) 888.5 888.5 — — — Long-term debt (b) 8,014.8 — 3,063.4 1,592.6 3,358.8 $ 11,938.9 $ 3,709.1 $ 3,178.7 $ 1,625.9 $ 3,425.2 (a) Excludes non - financial liabilities (b) Excludes deferred financing costs and discounts Contractual maturities by period As at December 31, 2017 Total Less than 1 year 1-3 years 4-5 years After 5 years Accounts payable and accrued liabilities $ 415.3 $ 415.3 $ — $ — $ — Dividends payable 32.0 32.0 — — — Short-term debt 46.8 46.8 — — — Other current liabilities (a) 22.4 22.4 — — — Other long-term liabilities (a) 146.0 — 25.7 20.8 99.5 Risk management contract liabilities 71.4 57.6 11.1 2.7 — Current portion of long-term debt (b) 188.9 188.9 — — — Long-term debt (b) 3,450.9 — 1,009.1 363.8 2,078.0 $ 4,373.7 $ 763.0 $ 1,045.9 $ 387.3 $ 2,177.5 (a) Excludes non - financial liabilities (b) Excludes deferred financing costs and discounts |
Natural Gas [Member] | |
Derivative [Line Items] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | December 31, 2018 Fixed price (per GJ) Period (months) Notional volume (GJ) Fair Value ($ millions) Sales 1.07 to 12.19 1-178 858,640,810 19.0 Purchases 0.69 to 16.26 1-179 1,638,207,391 (179.5) Swaps 2.56 to 15.37 1-231 621,578,572 20.9 December 31, 2017 Fixed price (per GJ) Period (months) Notional volume (GJ) Fair Value ($ millions) Sales 0.42 to 6.89 1-60 94,804,039 14.8 Purchases 0.52 to 6.40 1-48 61,980,315 (16.8) Swaps 2.86 to 9.38 1-10 6,039,642 7.9 |
NGL Frac Spread [Member] [Member] | |
Derivative [Line Items] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | December 31, 2018 Fixed price Period (months) Notional volume Fair Value ($ millions) Propane swaps $38.89 to $47.63/bbl 1-12 1,725,114 Bbl 12.6 Butane swaps $52.95 to $55.26/bbl 1-12 74,371 Bbl 1.2 Crude oil swaps $79.64 to $86.28/bbl 1-12 329,230 Bbl 6.0 Natural gas swaps $1.38 to $1.68/GJ 1-12 9,490,365 GJ (3.8) December 31, 2017 Fixed price Period (months) Notional volume Fair Value ($ millions) Propane swaps $28.77 to $49.21 /Bbl 1-12 1,992,927 Bbl (10.9) Butane swaps $47.83 to $54.67 /Bbl 1-12 130,088 Bbl (0.3) Crude oil swaps $61.05 to $75.64 /Bbl 1-12 518,665 Bbl (4.4) Natural gas swaps $0.42 to $2.27 /GJ 1-12 11,428,515 GJ (8.4) |
Power [Member] | |
Derivative [Line Items] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | December 31, 2018 Fixed price (per MWh) Period (months) Notional volume (MWh) Fair Value ($ millions) Power sales 26.90 to 95.03 1-60 11,881,575 (1.9) Power purchases 25.50 to 50.25 1-42 8,507,874 16.4 Swap purchases (6.07) to 76.18 1-48 20,957,180 (22.3) December 31, 2017 Fixed price (per MWh) Period (months) Notional volume (MWh) Fair Value ($ millions) Power sales 38.20 to 95.03 1-60 2,169,321 (2.5) Power purchases 58.50 1-12 17,520 (4.5) Swap purchases 37.50 to 63.50 1-48 1,563,160 6.5 |
REVENUE (Tables)
REVENUE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
REVENUE [Abstract] | |
Disaggregation of Revenue by Major Sources | Year ended December 31, 2018 Utilities Midstream Power Corporate Total Revenue from contracts with customers Commodity sales contracts $ — $ 665.2 $ 497.5 $ — $ 1,162.7 Midstream service contracts — 205.0 — — 205.0 Gas sales and transportation services 1,684.3 — — — 1,684.3 Storage services 35.4 — — — 35.4 Other 10.7 0.6 25.1 — 36.4 Total revenue from contracts with customers $ 1,730.4 $ 870.8 $ 522.6 $ — $ 3,123.8 Other sources of revenue Revenue from alternative revenue programs (a) $ 21.7 $ — $ — $ — $ 21.7 Leasing revenue (b) 0.6 96.6 354.9 — 452.1 Risk management and trading activities (c)(d) 1.0 377.6 268.5 (2.9) 644.2 Other (1.1) (0.4) 16.0 0.4 14.9 Total revenue from other sources $ 22.2 $ 473.8 $ 639.4 $ (2.5) $ 1,132.9 Total revenue $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5) $ 4,256.7 (a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d). (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues of $ 264.2 million associated with the GAIL Global (USA) L NG LLC (GAIL) contract, which are in scope of ASC 606, are reported in the risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The contract has a term of 20 years and began on March 31, 2018. |
Schedule of Estimated Revenue Related to Performance Obligations | 2019 2020 2021 2022 2023 > 2023 Total Midstream service contracts $ 52.2 $ 55.7 $ 32.3 $ 31.9 $ 28.0 $ 192.4 $ 392.5 Gas sales and transportation services 0.6 0.6 0.6 0.6 0.6 3.2 6.2 Storage services 36.7 36.3 36.3 36.3 36.3 299.8 481.7 Other 37.0 10.5 1.6 0.8 0.8 3.2 53.9 Subtotals $ 126.5 $ 103.1 $ 70.8 $ 69.6 $ 65.7 $ 498.6 $ 934.3 |
SHAREHOLDERS' EQUITY (Tables)
SHAREHOLDERS' EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SHAREHOLDERS' EQUITY [Abstract] | |
Schedule of Common Shares Issued and Outstanding | Common Shares Issued and Outstanding Number of shares Amount January 1, 2017 166,906,833 $ 3,773.4 Shares issued for cash on exercise of options 240,125 6.5 Deferred taxes on share issuance cost — (8.3) Shares issued under DRIP 8,132,258 236.3 December 31, 2017 175,279,216 4,007.9 Shares issued on conversion of subscription receipts, net of issuance costs 84,510,000 2,305.6 Shares issued for cash on exercise of options 57,275 1.3 Deferred taxes on share issuance costs — 13.3 Shares issued under DRIP 15,377,575 325.8 Issued and outstanding at December 31, 2018 275,224,066 $ 6,653.9 |
Schedule of Preferred Shares Issued and Outstanding | As at December 31, 2018 December 31, 2017 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 5,511,220 $ 137.8 5,511,220 $ 137.8 Series B 2,488,780 62.2 2,488,780 62.2 Series C 8,000,000 205.6 8,000,000 205.6 Series E 8,000,000 200.0 8,000,000 200.0 Series G 8,000,000 200.0 8,000,000 200.0 Series I 8,000,000 200.0 8,000,000 200.0 Series K 12,000,000 300.0 12,000,000 300.0 Washington Gas $4.80 series 150,000 19.7 — — $4.25 series 70,600 9.4 — — $5.00 series 60,000 7.9 — — Share issuance costs, net of taxes (27.9) (27.9) Fair value adjustment on WGL Acquisition (note 3) 4.1 — 52,280,600 $ 1,318.8 52,000,000 $ 1,277.7 |
Schedule of Common and Preferred Stock Outstanding Roll Forward | Common Shares Issued and Outstanding Number of shares Amount January 1, 2017 166,906,833 $ 3,773.4 Shares issued for cash on exercise of options 240,125 6.5 Deferred taxes on share issuance cost — (8.3) Shares issued under DRIP 8,132,258 236.3 December 31, 2017 175,279,216 4,007.9 Shares issued on conversion of subscription receipts, net of issuance costs 84,510,000 2,305.6 Shares issued for cash on exercise of options 57,275 1.3 Deferred taxes on share issuance costs — 13.3 Shares issued under DRIP 15,377,575 325.8 Issued and outstanding at December 31, 2018 275,224,066 $ 6,653.9 Preferred Shares As at December 31, 2018 December 31, 2017 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 5,511,220 $ 137.8 5,511,220 $ 137.8 Series B 2,488,780 62.2 2,488,780 62.2 Series C 8,000,000 205.6 8,000,000 205.6 Series E 8,000,000 200.0 8,000,000 200.0 Series G 8,000,000 200.0 8,000,000 200.0 Series I 8,000,000 200.0 8,000,000 200.0 Series K 12,000,000 300.0 12,000,000 300.0 Washington Gas $4.80 series 150,000 19.7 — — $4.25 series 70,600 9.4 — — $5.00 series 60,000 7.9 — — Share issuance costs, net of taxes (27.9) (27.9) Fair value adjustment on WGL Acquisition (note 3) 4.1 — 52,280,600 $ 1,318.8 52,000,000 $ 1,277.7 |
Summary of Cumulative Redeemable Preferred Shares | Current yield Annual dividend per share (b) Redemption price per share Redemption and conversion option date (c)(d) Right to convert into (d) AltaGas Series A (e) 3.38% $0.845 $25 September 30, 2020 Series B Series B (f) Floating (f) Floating (f) $25 September 30, 2020 (g) Series A Series C (h) 5.29% US$1.3225 US$25 September 30, 2022 Series D Series E (e) 5.393% $1.34825 $25 December 31, 2023 Series F Series G (e) 4.75% $1.1875 $25 September 30, 2019 Series H Series I (i) 5.25% $1.3125 $25 December 31, 2020 Series J Series K (j) 5.00% $1.25 $25 March 31, 2022 Series L Washington Gas $4.80 series 4.27% US$4.80 US$101 n/a n/a $4.25 series 4.27% US$4.25 US$105 n/a n/a $5.00 series 4.27% US$5.00 US$102 n/a n/a (a) The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares , Series F Shares , Series H Shares , and Series J Shares , and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares , Series H Shares , Series J Shares , and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. (b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. (c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. (d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter. (e) Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five -year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). (f) Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2018, the floating quarterly dividend rate for Series B Shares is $0.26938 per share for the period starting December 31, 2018 to, but excluding, March 31, 2019. (g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. (h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent. (i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum. (j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum. |
Summary of Share Option Activity | As at December 31, 2018 December 31, 2017 Options outstanding Options outstanding Number of options Exercise price (a) Number of options Exercise price (a) Share options outstanding, beginning of year 4,533,761 $ 32.35 4,119,386 $ 32.39 Granted 2,811,460 16.69 848,000 30.80 Exercised (57,275) 20.68 (240,125) 24.63 Forfeited (878,013) 36.47 (193,500) 36.36 Expired (100,750) 14.60 — — Share options outstanding, end of year 6,309,183 $ 25.18 4,533,761 $ 32.35 Share options exercisable, end of year 2,897,723 $ 32.01 3,326,197 $ 31.93 (a) Weighted averag e . |
Summary of Employee Share Option Plan | Options outstanding Options exercisable Weighted Weighted average Weighted Weighted average Number average remaining Number average remaining outstanding exercise price contractual life exercisable exercise price contractual life $14.24 to $18.00 2,322,635 $ 14.55 5.91 28,000 $ 17.10 1.33 $18.01 to $25.08 425,000 20.76 1.83 425,000 20.76 1.83 $25.09 to $50.89 3,561,548 32.65 3.48 2,444,723 34.14 2.95 6,309,183 $ 25.18 4.26 2,897,723 $ 32.01 2.77 |
Summary of Fair Value of Options Granted | Year ended December 31 2018 2017 Fair value per option ($) 1.27 1.91 Risk-free interest rate (%) 1.99 1.31 Expected life (years) 6 6 Expected volatility (%) 23.23 21.05 Annual dividend per share ($) (a) 1.18 2.12 Forfeiture rate (%) — — |
Schedule of MTIP and DSUP Activity | PUs, RUs, and DSUs December 31, 2018 December 31, 2017 (number of units) Balance, beginning of year 564,549 364,839 Acquired (a) 5,291,621 — Granted 9,502,347 386,126 Additional units added by performance factor — 24,301 Vested and paid out (148,154) (221,775) Forfeited (66,522) (27,279) Units in lieu of dividends 55,934 38,337 Outstanding, end of year 15,199,775 564,549 |
NET INCOME PER COMMON SHARE (Ta
NET INCOME PER COMMON SHARE (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
NET INCOME PER COMMON SHARE [Abstract] | |
Summary of Net Income per Common Share | Year ended December 31 2018 2017 Numerator: Net income (loss) applicable to controlling interests $ (435.1) $ 91.6 Less: Preferred share dividends (66.6) (61.3) Net income (loss) applicable to common shares $ (501.7) $ 30.3 Denominator: (millions) Weighted average number of common shares outstanding 222.6 171.0 Dilutive equity instruments (a) 0.1 0.3 Weighted average number of common shares outstanding - diluted 222.7 171.3 Basic net income (loss) per common share $ (2.25) $ 0.18 Diluted net income (loss) per common share $ (2.25) $ 0.18 (a) Includes all options that have a strike price lower than the share price of AltaGas' common shares as at December 31, 2018 and 2017 . |
OTHER INCOME (Tables)
OTHER INCOME (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
OTHER INCOME [Abstract] | |
Schedule of Other Income (Loss) | Year ended December 31 2018 2017 Losses from sale of assets $ (10.6) $ (2.7) Other components of net benefit cost (note 2) 18.9 — Interest income and other revenue 2.7 8.7 Gains (losses) on investments (10.1) 3.6 $ 0.9 $ 9.6 |
OPERATING LEASES (Tables)
OPERATING LEASES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
OPERATING LEASES [Abstract] | |
Schedule of Future Minimum Revenue from Operating Leases | 2019 194.4 2020 155.3 2021 111.9 2022 112.0 2023 104.2 |
PENSION PLANS AND RETIREE BEN_2
PENSION PLANS AND RETIREE BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
PENSION PLANS AND RETIREE BENEFITS [Abstract] | |
Summary of Defined Benefit Plans | Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2018 Benefit Benefits Benefit Benefits Benefit Benefits Accrued benefit obligation Balance, beginning of year $ 165.6 $ 15.8 $ 303.8 $ 82.7 $ 469.4 $ 98.5 Plans disposed (note 4) (132.1) (13.6) — — (132.1) (13.6) Actuarial gain (0.8) (0.1) (67.7) (33.8) (68.5) (33.9) Current service cost 2.4 0.1 16.2 5.3 18.6 5.4 Member contributions — — — 2.1 — 2.1 Interest cost 1.2 0.1 38.0 10.9 39.2 11.0 Benefits paid (2.7) — (43.2) (13.4) (45.9) (13.4) Expenses paid — — (0.9) (0.1) (0.9) (0.1) Plan combinations 0.7 — 1,311.7 382.9 1,312.4 382.9 Plan amendments — (0.4) — — — (0.4) Foreign exchange translation — — 77.4 21.4 77.4 21.4 Balance, end of year $ 34.3 $ 1.9 $ 1,635.3 $ 458.0 $ 1,669.6 $ 459.9 Plan assets Fair value, beginning of year $ 115.2 $ 8.1 $ 248.7 $ 70.8 $ 363.9 $ 78.9 Plans disposed (note 4) (102.1) (8.1) — — (102.1) (8.1) Actual return on plan assets (0.3) — (54.7) (37.2) (55.0) (37.2) Employer contributions 3.4 — 7.6 2.5 11.0 2.5 Member contributions — — — 2.1 — 2.1 Benefits paid (2.7) — (43.2) (13.4) (45.9) (13.4) Expenses paid — — (0.9) (0.1) (0.9) (0.1) Plan combinations 0.3 — 1,133.2 732.7 1,133.5 732.7 Foreign exchange translation — — 63.4 33.8 63.4 33.8 Fair value, end of year $ 13.8 $ — $ 1,354.1 $ 791.2 $ 1,367.9 $ 791.2 Net amount recognized $ (20.5) $ (1.9) $ (281.2) $ 333.2 $ (301.7) $ 331.3 Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2017 Benefit Benefits Benefit Benefits Benefit Benefits Accrued benefit obligation Balance, beginning of year $ 150.0 $ 16.4 $ 290.5 $ 72.7 $ 440.5 $ 89.1 Actuarial loss (gain) 8.3 (1.6) 23.2 14.4 31.5 12.8 Current service cost 7.9 0.7 8.0 1.8 15.9 2.5 Member contributions 0.2 — — — 0.2 — Interest cost 5.8 0.6 11.7 2.9 17.5 3.5 Benefits paid (6.3) (0.3) (8.6) (3.2) (14.9) (3.5) Expenses paid (0.3) — (0.8) (0.1) (1.1) (0.1) Plan settlements — — — (0.5) — (0.5) Foreign exchange translation — — (20.2) (5.3) (20.2) (5.3) Balance, end of year $ 165.6 $ 15.8 $ 303.8 $ 82.7 $ 469.4 $ 98.5 Plan assets Fair value, beginning of year $ 101.5 $ 6.8 $ 226.9 $ 67.2 $ 328.4 $ 74.0 Actual return on plan assets 8.5 0.4 37.9 11.0 46.4 11.4 Employer contributions 11.6 1.2 9.5 0.6 21.1 1.8 Member contributions 0.2 — — — 0.2 — Benefits paid (6.3) (0.3) (8.6) (3.2) (14.9) (3.5) Expenses paid (0.3) — (0.8) (0.1) (1.1) (0.1) Foreign exchange translation — — (16.2) (4.7) (16.2) (4.7) Fair value, end of year $ 115.2 $ 8.1 $ 248.7 $ 70.8 $ 363.9 $ 78.9 Net amount recognized $ (50.4) $ (7.7) $ (55.1) $ (11.9) $ (105.5) $ (19.6) |
Schedule of Amounts Included in the Consolidated Balance Sheets | December 31, 2018 December 31, 2017 Post- Post- Defined Retirement Defined Retirement Benefit Benefits Total Benefit Benefits Total Prepaid post-retirement benefits $ — $ 341.4 $ 341.4 $ — $ — $ — Accounts payable and accrued liabilities (27.6) — (27.6) (0.6) — (0.6) Future employee obligations (273.9) (10.3) (284.2) (104.9) (19.6) (124.5) $ (301.5) $ 331.1 $ 29.6 $ (105.5) $ (19.6) $ (125.1) |
Schedule of Funded Status Based on Accumulated Benefit Obligation | December 31, 2018 December 31, 2017 Canada United States Canada United States Accumulated benefit obligation (a) $ (32.9) $ (1,525.6) $ (143.9) $ (274.2) Fair value of plan assets 13.8 1,354.1 115.2 248.7 Funded status $ (19.1) $ (171.5) $ (28.7) $ (25.5) (a) Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels. |
Summary of Amounts Recorded in Other Comprehensive Income (Loss) | Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2018 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ (0.3) $ 0.4 $ (0.2) $ — $ (0.5) $ 0.4 Net actuarial loss (8.7) (0.5) (10.7) (5.0) (19.4) (5.5) Recognized in AOCI pre-tax $ (9.0) $ (0.1) $ (10.9) $ (5.0) $ (19.9) $ (5.1) Increase by the amount included in deferred tax liabilities 2.4 — 2.2 1.4 4.6 1.4 Net amount in AOCI after-tax $ (6.6) $ (0.1) $ (8.7) $ (3.6) $ (15.3) $ (3.7) Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2017 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ (0.4) $ — $ — $ — $ (0.4) $ — Net actuarial loss (13.9) (1.3) — — (13.9) (1.3) Recognized in AOCI pre-tax $ (14.3) $ (1.3) $ — $ — $ (14.3) $ (1.3) Increase (decrease) by the amount included in deferred tax liabilities 4.0 0.3 (0.1) — 3.9 0.3 Net amount in AOCI after-tax $ (10.3) $ (1.0) $ (0.1) $ — $ (10.4) $ (1.0) |
Summary of Amounts Recorded in A Regulatory Asset (Liability) | Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2018 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ — $ — $ 0.8 $ (110.2) $ 0.8 $ (110.2) Net actuarial gain (loss) — — 188.2 (52.6) 188.2 (52.6) Recognized in regulatory asset (liability) $ — $ — $ 189.0 $ (162.8) $ 189.0 $ (162.8) Canada United States Total Post- Post- Post- Defined Retirement Defined Retirement Defined Retirement Year ended December 31, 2017 Benefit Benefits Benefit Benefits Benefit Benefits Past service cost $ — $ — $ (1.2) $ 5.6 $ (1.2) $ 5.6 Net actuarial gain (loss) (30.6) 0.4 (74.0) (12.8) (104.6) (12.4) Recognized in regulatory asset (liability) $ (30.6) $ 0.4 $ (75.2) $ (7.2) $ (105.8) $ (6.8) |
Schedule of Amounts to be Amortized from AOCI in the Next Fiscal Year | Post- Defined Retirement Amounts to be amortized in the next fiscal year from AOCI Benefit Benefits Past service costs $ 0.1 $ 0.2 Actuarial losses 0.5 — Total $ 0.6 $ 0.2 |
Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year | Post- Amounts to be amortized in the next fiscal year from regulatory Defined Retirement assets (liabilities) Benefit Benefits Past service costs $ 0.2 $ (21.3) Actuarial losses 9.1 0.1 Total $ 9.3 $ (21.2) |
Schedule of Net Periodic Benefit Expense | Year ended December 31, 2018 Canada United States Total Post- Post- Post- Defined retirement Defined retirement Defined retirement Benefit Benefits Benefit Benefits Benefit Benefits Current service cost (a) $ 2.4 $ 0.1 $ 16.2 $ 5.3 $ 18.6 $ 5.4 Interest cost (b) 1.2 0.1 38.0 10.9 39.2 11.0 Expected return on plan assets (b) (0.5) — (49.9) (21.6) (50.4) (21.6) Amortization of past service cost (b) 0.1 — — — 0.1 — Amortization of net actuarial loss (b) 0.6 — — — 0.6 — Amortization of regulatory asset (b) — — 7.8 (11.1) 7.8 (11.1) Net benefit cost (income) recognized $ 3.8 $ 0.2 $ 12.1 $ (16.5) $ 15.9 $ (16.3) (a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “Other Income” on the Consolidated Statements of Income. Year ended December 31, 2017 Canada United States Total Post- Post- Post- Defined retirement Defined retirement Defined retirement Benefit Benefits Benefit Benefits Benefit Benefits Current service cost (a) $ 7.9 $ 0.7 $ 8.0 $ 1.8 $ 15.9 $ 2.5 Interest cost (b) 5.8 0.6 11.7 2.9 17.5 3.5 Expected return on plan assets (b) (5.9) (0.2) (16.9) (4.7) (22.8) (4.9) Settlement of plan (b) — — — 0.2 — 0.2 Amortization of past service cost (b) 0.2 — — — 0.2 — Amortization of net actuarial loss (b) 0.7 — — — 0.7 — Amortization of regulatory asset/liability (b) 1.3 0.1 6.5 (0.3) 7.8 (0.2) Net benefit cost (income) recognized $ 10.0 $ 1.2 $ 9.3 $ (0.1) $ 19.3 $ 1.1 (a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “Other Income” on the Consolidated Statements of Income. |
Schedule of Collective Investment Mixes for Plan Assets | Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 1.7 $ 1.7 $ — 12.3 Canadian equities 3.7 3.7 — 26.8 Foreign equities 2.1 2.1 — 15.2 Fixed income 5.5 5.5 — 39.9 Real estate 0.8 — 0.8 5.8 $ 13.8 $ 13.0 $ 0.8 100.0 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 6.3 $ 6.3 $ — 0.3 Canadian equities 2.1 2.1 — 0.1 Foreign equities (a) 273.2 270.6 2.6 12.7 Fixed income 850.1 99.2 750.9 39.6 Derivatives 9.3 — 9.3 0.4 Other 10.9 — 10.9 0.5 Total investments in the fair value hierarchy $ 1,151.9 378.2 773.7 53.6 Investments measured at net asset value using the NAV practical expedient (b) Commingled funds and pooled separate accounts (c) 945.3 44.2 Private Equity/Limited Partnership (d) 48.2 2.2 Total fair value of plan investments $ 2,145.4 100.0 Net payable (e) (0.1) — $ 2,145.3 100.0 (b) Investments in foreign equities include U.S. and international securities. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans. (e) At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies. (f) At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. |
Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations | Post- Post- Significant actuarial assumptions used in measuring Defined Retirement Defined Retirement net benefit plan costs Benefit Benefits Benefit Benefits Year ended December 31 2018 2017 Discount rate (%) 3.25 - 4.30 3.60 - 4.30 2.65 - 4.20 4.00 - 4.20 Expected long-term rate of return on plan assets (%) (a) 3.20 - 7.60 3.75 - 7.60 6.18 - 7.30 3.10 - 7.30 Rate of compensation increase (%) 2.75 - 4.10 4.10 2.75 - 4.00 3.25 Average remaining service life of active employees (years) 9.6 14.1 12.7 13.5 (a) Only applicable for funded plans Post- Post- Significant actuarial assumptions used in measuring Defined Retirement Defined Retirement benefit obligations Benefit Benefits Benefit Benefits As at December 31 2018 2017 Discount rate (%) 3.60 - 4.40 3.90 - 4.50 2.80 - 3.70 3.60 - 3.70 Rate of compensation increase (%) 2.75 - 4.10 4.10 2.75 - 4.00 3.25 |
Summary of Assumed Health Care Cost Trend Rates | Increase Decrease Service and interest costs $ 1.7 $ (1.3) Accrued benefit obligation $ 19.8 $ (16.0) |
Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans | Post- Defined Retirement Benefit Benefits Expected employer contributions: 2019 $ 41.4 $ 0.1 Expected benefit payments: 2019 $ 109.8 $ 25.3 2020 92.2 24.6 2021 95.3 25.0 2022 101.0 25.4 2023 99.4 25.5 2024 - 2028 $ 521.9 $ 130.9 |
COMMITMENTS, CONTINGENCIES AN_2
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
COMMITMENTS, CONTINGENCIES AND GUARANTEES [Abstract] | |
Summary of Future Payment Commitments | 2019 2020 2021 2022 2023 2024 and beyond Total Gas purchase (a) $ 3,157.1 $ 2,940.5 $ 2,639.3 $ 2,527.4 $ 2,349.9 $ 30,309.2 $ 43,923.4 Electricity purchase (c) 533.1 368.6 139.2 38.6 5.7 0.4 1,085.6 Service agreements (b)(d) 74.3 48.2 30.9 17.3 14.8 168.0 353.5 Pipeline and storage services (e) 861.6 862.2 818.8 795.6 781.7 4,645.3 8,765.2 Capital projects (f) 119.2 — — — — — 119.2 Operating leases (g) 23.9 30.9 29.4 28.0 25.8 164.8 302.8 Environmental (h) 6.1 4.7 3.0 0.5 0.4 0.5 15.2 Merger commitments 29.3 30.8 22.8 19.2 19.2 62.1 183.4 $ 4,804.6 $ 4,285.9 $ 3,683.4 $ 3,426.6 $ 3,197.5 $ 35,350.3 $ 54,748.3 (a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (b) In 2014, AltaGas' Blythe facility entered into a Long - Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hour per CT, or 25 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2018, the total commitment was $190.9 million payable over the next 16 years, of which $59.6 million is expected to be paid over the next five years. (c) AltaGas enters into contracts to purchase electricity from various suppliers for its utilities. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include $44.1 million of commitments related to renewable energy credits. (d) In 2017, AltaGas entered into a 12 -year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed and variable fees of approximately $60.1 million over the term of the contract. (e) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (f) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. (g) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, office and other equipment. (h) Environmental commitments relate to future costs associated with sites where AltaGas or its predecessors may have operated manufactured gas plants. |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
RELATED PARTY TRANSACTIONS [Abstract] | |
Summary of Related Party Amounts Included in Balance Sheets | As at December 31, 2018 December 31, 2017 Due from related parties Accounts receivable (a) $ 60.8 $ 0.8 Long-term investments and other assets (b) 45.0 75.0 $ 105.8 $ 75.8 Due to related parties Accounts payable (c) 6.3 3.2 Risk management liabilities - current (d) 0.9 — $ 7.2 $ 3.2 (a) Receivable s from joint ventures and ACI. (b) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021 . As at December 31, 2018, Petrogas had drawn $45.0 million (December 31, 2017 - $75.0 million) under the facility. (c) Payables to ACI and a joint venture . (d) Foreign exchange hedge with ACI. |
Schedule of Related Party Transactions | Year ended December 31 2018 2017 Revenue (a) $ 68.4 $ 15.0 Cost of sales (b) $ (4.2) $ (6.5) Operating and administrative expenses (c) $ 1.3 $ — Other income (d) $ 9.2 $ 4.4 (a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI . In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil ). (b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sa le of natural gas liquids to affiliate s . (c) Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive. (d) Interest income from loans to Petrogas (secured loan facility) and loans to ACI . Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018. |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract] | |
Schedule of Changes in Operating Assets and Liabilities | Year ended December 31 2018 2017 Source (use) of cash: Accounts receivable $ (526.9) $ (55.6) Inventory (100.8) 4.7 Other current assets 12.5 7.0 Regulatory assets (current) (15.8) (0.2) Accounts payable and accrued liabilities 237.9 85.4 Customer deposits (13.3) (2.8) Regulatory liabilities (current) 69.2 (4.8) Other current liabilities (5.9) 13.0 Other operating assets and liabilities (143.4) (44.8) Changes in operating assets and liabilities $ (486.5) $ 1.9 |
Schedule of Supplemental Cash Payments | Year ended December 31 2018 2017 Interest paid (net of capitalized interest) $ 288.9 $ 151.1 Income taxes paid $ 36.9 $ 36.3 |
Reconciliation of Cash and Restricted Cash Balances | As at December 31 2018 2017 Cash and cash equivalents $ 101.6 $ 27.3 Restricted cash holdings from customers - current 4.1 8.9 Restricted cash holdings from customers - non-current 6.1 7.5 Restricted cash included in prepaid expenses and other current assets (a) 27.6 — Restricted cash included in long-term investments and other assets (a) 61.7 — Cash, cash equivalents and restricted cash per consolidated statement of cash flow $ 201.1 $ 43.7 The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relates to Rabbi trusts associated with WGL’s pension plans (Note 28). On the date of the WGL Acquisition, the restricted cash balances related to Rabbi trusts was $81.0 million. |
SEGMENTED INFORMATION (Tables)
SEGMENTED INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SEGMENTED INFORMATION [Abstract] | |
Reconciliation Of Segment Revenue | Year ended December 31, 2018 Utilities Midstream Power Corporate Total External revenue (note 23) $ 1,752.6 $ 1,344.6 $ 1,162.0 $ (2.5) $ 4,256.7 Intersegment revenue 13.0 90.4 9.0 0.1 112.5 Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4) $ 4,369.2 |
Schedule of Geographic Information | Year ended December 31 2018 2017 Revenue (a) Canada $ 1,626.8 $ 1,508.8 United States 2,553.0 1,109.9 Total $ 4,179.8 $ 2,618.7 (a) Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts. As at December 31 2018 2017 Property, plant and equipment Canada $ 2,348.2 $ 4,320.5 United States 8,581.4 2,369.3 Total $ 10,929.6 $ 6,689.8 |
Schedule of Segment Composition | Year ended December 31, 2018 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 1,765.6 $ 1,435.0 $ 1,171.0 $ (2.4) $ (112.5) $ 4,256.7 Cost of sales (838.3) (976.4) (743.7) — 103.1 (2,455.3) Operating and administrative (727.4) (201.7) (159.1) (50.6) 9.8 (1,129.0) Accretion expenses (0.1) (4.0) (6.8) — — (10.9) Depreciation and amortization (165.8) (84.4) (130.5) (13.3) — (394.0) Provisions on assets (note 10) (193.7) (153.7) (381.3) — — (728.7) Income from equity investments 7.2 51.1 (10.4) — — 47.9 Other income (loss) 4.5 0.7 (5.9) 2.0 (0.4) 0.9 Foreign exchange gains — (0.2) (0.1) 4.8 — 4.5 Interest expense (103.9) (10.6) (8.9) (185.6) — (309.0) Loss before income taxes $ (251.9) $ 55.8 $ (275.7) $ (245.1) $ — $ (716.9) Net additions (reductions) to: Property, plant and equipment (b) $ 507.0 $ 383.4 $ (321.9) $ 4.0 $ — $ 572.5 Intangible assets $ 21.8 $ 4.7 $ 12.5 $ 6.7 $ — $ 45.7 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets. Year ended December 31, 2017 Utilities Midstream Power Corporate Intersegment Elimination (a) Total Segment revenue $ 1,126.7 $ 1,008.0 $ 631.7 $ (58.4) $ (151.8) $ 2,556.2 Cost of sales (610.1) (647.0) (242.8) — 142.8 (1,357.1) Operating and administrative (226.1) (165.0) (93.1) (97.5) 9.5 (572.2) Accretion expenses (0.1) (3.9) (6.9) — — (10.9) Depreciation and amortization (81.8) (68.6) (118.0) (14.0) — (282.4) Provision on assets — (6.6) (133.0) — — (139.6) Income from equity investments 2.6 22.0 6.8 — — 31.4 Other income (loss) 3.9 (0.9) 0.8 6.3 (0.5) 9.6 Foreign exchange gains — 0.2 — 1.5 — 1.7 Interest expense — — — (170.3) — (170.3) Income (loss) before income taxes $ 215.1 $ 138.2 $ 45.5 $ (332.4) $ — $ 66.4 Net additions (reductions) to: Property, plant and equipment (b) $ 124.3 $ 245.3 $ 16.5 $ 1.5 $ — $ 387.6 Intangible assets $ 2.1 $ 2.8 $ 13.2 $ 2.2 $ — $ 20.3 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets. |
Schedule of Goodwill and Total Assets by Segment | Utilities Midstream Power Corporate Total As at December 31, 2018 Goodwill $ 3,450.8 $ 426.4 $ 191.0 $ — $ 4,068.2 Segmented assets $ 12,991.3 $ 6,398.8 $ 3,814.7 $ 282.9 $ 23,487.7 As at December 31, 2017 Goodwill $ 664.7 $ 152.6 $ — $ — $ 817.3 Segmented assets $ 3,460.2 $ 3,096.8 $ 3,192.5 $ 282.7 $ 10,032.2 |
ORGANIZATION AND OVERVIEW OF _2
ORGANIZATION AND OVERVIEW OF THE BUSINESS (Narrative) (Details) customer in Millions, $ in Billions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2019 | Dec. 31, 2018CAD ($)MMcf / dstatesegmentcustomeritemMW | Dec. 13, 2018 | |
Organization And Overview Of Business [Line Items] | |||
Number of segments | segment | 3 | ||
Northwest Hydro Facilities [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Equity method investment, ownership interest | 55.00% | ||
Petrogas [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Equity method investment, ownership interest | 33.333% | ||
Utilities [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Number of customers | customer | 1.6 | ||
Utilities customers, base rate | $ | $ 3.7 | ||
Number of utilities jurisdictions | item | 5 | ||
Midstream [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Production capacity | MMcf / d | 1,500 | ||
Midstream [Member] | AIJVLP [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Equity method investment, ownership interest | 50.00% | ||
Midstream [Member] | Petrogas [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Equity method investment, ownership interest | 33.33% | ||
Power [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Power capacity | MW | 1,105 | ||
Power [Member] | Northwest Hydro Facilities [Member] | Subsequent Event [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Interest sold | 55.00% | ||
United States [Member] | Power [Member] | |||
Organization And Overview Of Business [Line Items] | |||
Number of states/provinces | state | 20 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) $ in Millions | Jan. 01, 2018CAD ($) | Dec. 31, 2018$ / shares | Dec. 31, 2018CAD ($)item |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Assets held for sale, expected sale period | 12 months | ||
Other portions of RU's and PSU's, value per share | $ / shares | $ 1 | ||
Accounting Standards Update 2016-01 [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Cumulative-effect adjustment to retained earnings | $ | $ 7 | ||
Accounting Standards Update 2017-07 [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ | $ 1.6 | ||
Pension Benefits [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Expected average remaining service period | 9 years 7 months 6 days | ||
Postretirement Health Coverage [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Expected average remaining service period | 14 years 1 month 6 days | ||
Normal Purchase Normal Sale (NPNS) Contracts [Member] | WGL Holdings [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Finite-Lived Intangible Asset, Useful Life | 20 years | ||
Minimum [Member] | Performance Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Performance multiplier | item | 0 | ||
Maximum [Member] | Performance Units [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Performance multiplier | item | 2 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Estimated Useful Lives of Property, Plant and Equipment) (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Minimum [Member] | Utilities [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 3 years |
Minimum [Member] | Midstream [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 3 years |
Minimum [Member] | Power [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 2 years |
Minimum [Member] | Corporate [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 1 year |
Maximum [Member] | Utilities [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 80 years |
Maximum [Member] | Midstream [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 45 years |
Maximum [Member] | Power [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 120 years |
Maximum [Member] | Corporate [Member] | |
Property Plant And Equipment [Line Items] | |
Useful life | 20 years |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Estimated Useful Lives of Finite-Lived Intangible Assets) (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Extraction And Transmission (E&T) Contracts [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 25 years |
Commodity Contract [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 5 years |
Minimum [Member] | Energy Services Relationships [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 5 years |
Minimum [Member] | Electricity Service Agreements [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 2 years |
Minimum [Member] | Software [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 3 years |
Minimum [Member] | Land Rights [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 5 years |
Minimum [Member] | Franchise And Consents [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 9 years |
Maximum [Member] | Energy Services Relationships [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 19 years |
Maximum [Member] | Electricity Service Agreements [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 60 years |
Maximum [Member] | Software [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 10 years |
Maximum [Member] | Land Rights [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 64 years |
Maximum [Member] | Franchise And Consents [Member] | |
Finite-Lived Intangible Assets [Line Items] | |
Intangible asset, useful life | 25 years |
ACQUISITION OF WGL HOLDINGS I_3
ACQUISITION OF WGL HOLDINGS INC. (Narrative) (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions | Jul. 06, 2018USD ($)$ / sharesshares | Jul. 06, 2018CAD ($)shares | Dec. 31, 2018CAD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Jul. 06, 2018CAD ($)$ / $ | Dec. 31, 2016CAD ($) |
Business Acquisition [Line Items] | |||||||
Goodwill | $ 4,068.2 | $ 4,068.2 | $ 817.3 | $ 856 | |||
Revenue | 4,256.7 | 2,556.2 | |||||
Net income (loss) | $ (435.1) | 91.6 | |||||
Meade Pipeline Co LLC [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Equity method investment, ownership interest | 55.00% | 55.00% | |||||
WGL Holdings [Member] | Meade Pipeline Co LLC [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Parent ownership interest | 55.00% | 55.00% | |||||
WGL Holdings [Member] | Mountain Valley Pipeline LLC [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Noncontrolling ownership interest | 10.00% | 10.00% | |||||
WGL Holdings [Member] | Stonewall Gas Gathering Systems LLC [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Equity method investment, ownership interest | 30.00% | 30.00% | |||||
WGL Holdings [Member] | Central Penn [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Equity method investment, ownership interest | 21.00% | 21.00% | |||||
WGL Holdings [Member] | Non-recurring Adjustments [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Net income (loss) | $ 132 | 19 | |||||
Meade Pipeline Co LLC [Member] | Central Penn [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Equity method investment, ownership interest | 39.00% | 39.00% | |||||
Public And Private Placement [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Proceeds from issuance of subscription receipts | $ 2.3 | ||||||
WGL Holdings [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Aggregate purchase price | $ 7,100 | 9,300 | |||||
Acquisition, assumption of debt | 2,500 | 3,300 | |||||
Acquisition, equity issued | $ 31 | 41 | |||||
Acquisition, share price | $ / shares | $ 88.25 | ||||||
Cash consideration | $ 4,600 | $ 6,000 | |||||
Shares issued on conversion of subscription receipts | shares | 84.5 | 84.5 | |||||
Exchange rate | $ / $ | 1.31 | ||||||
Fair value adjustment of property, plant and equipment | $ (92) | ||||||
Goodwill | $ 3,196 | ||||||
Intangible assets | $ 637 | ||||||
Fair value adjustment of equity interests | 464 | ||||||
Fair value adjustment of long-term debt | 87 | ||||||
Acquisition costs | 237.2 | 65.7 | |||||
Revenues of acquiree | $ 1,406 | ||||||
Income (loss) of acquiree | $ 113 | ||||||
WGL Holdings [Member] | Foreign Exchange Contracts, Gains (Losses) [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Revenue | $ 2 | $ 34 | |||||
WGL Holdings [Member] | Acquisition Credit Facility [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Proceeds from credit lines | $ 2,300 | $ 3,000 |
ACQUISITION OF WGL HOLDINGS I_4
ACQUISITION OF WGL HOLDINGS INC. (Schedule of Final Purchase Price Allocation) (Details) - CAD ($) $ in Millions | Jul. 06, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Business Acquisition [Line Items] | ||||
Goodwill | $ 4,068.2 | $ 817.3 | $ 856 | |
WGL Holdings [Member] | ||||
Business Acquisition [Line Items] | ||||
Purchase consideration | $ 5,973 | |||
Current assets | 1,187 | |||
Property, plant and equipment | 5,943 | |||
Intangible assets | 637 | |||
Regulatory assets | 402 | |||
Long-term investments | 1,411 | |||
Other long-term assets | 449 | |||
Current liabilities | (1,798) | |||
Long-term debt | (2,548) | |||
Preferred shares | (41) | |||
Regulatory liabilities | (1,125) | |||
Deferred income taxes | (772) | |||
Other long-term liabilities | (959) | |||
Non-controlling interest | (9) | |||
Fair value of net assets acquired | 2,777 | |||
Goodwill | $ 3,196 |
ACQUISITION OF WGL HOLDINGS I_5
ACQUISITION OF WGL HOLDINGS INC. (Summary of Pro Forma Information) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
ACQUISITION OF WGL HOLDINGS INC. [Abstract] | ||
Pro forma revenue | $ 5,962 | $ 5,704 |
Pro forma net income (loss) after taxes | $ (304) | $ 450 |
SALE OF MINORITY INTEREST AND_2
SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS (Narrative) (Details) $ / shares in Units, $ in Millions, $ in Millions | Dec. 31, 2018 | Dec. 11, 2018CAD ($) | Nov. 13, 2018USD ($)MW | Oct. 25, 2018CAD ($)$ / shares | Jun. 22, 2018CAD ($) | Mar. 31, 2018CAD ($) | Mar. 31, 2017CAD ($) | Jun. 30, 2018CAD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 13, 2018 |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Proceeds from non-controlling interest recorded as contributed surplus | $ 3 | ||||||||||
Gains (losses) from sale of assets | $ (10.6) | (2.7) | |||||||||
AltaGas Canada [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Pretax provision | 193.7 | ||||||||||
Proceeds from sale of shares | $ 892.2 | ||||||||||
Gains (losses) from sale of assets | $ (0.5) | ||||||||||
AltaGas Canada [Member] | Northwest Hydro Facilities [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Noncontrolling ownership interest | 10.00% | 10.00% | |||||||||
AltaGas Canada [Member] | IPO [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Sale price of shares | $ / shares | $ 14.50 | ||||||||||
Ownership interest after transaction | 37.00% | ||||||||||
Northwest Hydro Facilities [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Equity method investment, ownership interest | 55.00% | ||||||||||
Proceeds from asset dispositions | $ 921.6 | ||||||||||
Noncontrolling interest increase | $ 420.4 | ||||||||||
Proceeds from non-controlling interest recorded as deferred tax labilities | 153.3 | ||||||||||
Proceeds from non-controlling interest recorded as contributed surplus | $ 335.2 | ||||||||||
Northwest Hydro Facilities [Member] | Sale of Minority Interest and Other Dispositions [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Equity method investment, ownership interest | 35.00% | ||||||||||
San Joaquin Facilities [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Proceeds from asset dispositions | $ 299.4 | ||||||||||
Pretax provision | $ 340.6 | ||||||||||
Gains (losses) from sale of assets | (14.4) | ||||||||||
Power capacity | MW | 523 | ||||||||||
Busch Ranch [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Proceeds from asset dispositions | $ 16.3 | ||||||||||
Gains (losses) from sale of assets | (3.2) | ||||||||||
Certent Non-Core Gas Facilities [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Proceeds from asset dispositions | $ 7 | ||||||||||
Gains (losses) from sale of assets | $ 1.3 | ||||||||||
EDS And JFP Transmission Assets [Member] | |||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | |||||||||||
Proceeds from asset dispositions | $ 67 | ||||||||||
Gains (losses) from sale of assets | $ (3.4) |
ASSETS HELD FOR SALE (Narrative
ASSETS HELD FOR SALE (Narrative) (Details) - CAD ($) shares in Millions, $ in Millions | Dec. 13, 2018 | Sep. 30, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Number of shares of investment sold | 43.7 | |||||
Non-Core Midstream and Power Assets in Canada [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Aggregate purchase price | $ 165 | |||||
Assets held for sale | $ 102.1 | 102.1 | ||||
Liabilities held for sale | $ 10.8 | 10.8 | ||||
Number of shares of investment sold | 43.7 | |||||
Northwest Hydro Facilities [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Assets held for sale | $ 1,350.2 | |||||
Liabilities held for sale | $ 160.6 | |||||
Equity Method Investment, Ownership Percentage | 55.00% | |||||
Proceeds from Sale of Property Held-for-sale | $ 1,370 | |||||
Annual Payments Related To Assets Held For Sale | $ 11 | |||||
Electricity purchase agreement term | 60 years | |||||
Architect of the Capitol (AOC) Project [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Pretax provision | $ 6 | |||||
Assets held for sale | 76.6 | $ 76.6 | ||||
Property, Plant and Equipment [Member] | Non-Core Midstream and Power Assets in Canada [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Pretax provision | 121.4 | |||||
Intangible Assets [Member] | Non-Core Midstream and Power Assets in Canada [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Pretax provision | 0.5 | |||||
Goodwill [Member] | Non-Core Midstream and Power Assets in Canada [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Pretax provision | $ 5.1 | |||||
Held-For-Sale [Member] | ||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||
Assets held for sale | 1,528.9 | 1,528.9 | $ 6 | |||
Liabilities held for sale | $ 171.4 | $ 171.4 | $ 0.3 |
ASSETS HELD FOR SALE (Schedule
ASSETS HELD FOR SALE (Schedule of Assets Held for Sale) (Details) - Held-For-Sale [Member] - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||
Cash | $ 4.9 | |
Accounts receivable | 85.2 | $ 0.3 |
Inventory | 0.5 | |
Property, plant and equipment | 1,189.6 | 5.3 |
Intangible assets | 248.7 | 0.1 |
Goodwill | 0.3 | |
Total assets held for sale | 1,528.9 | 6 |
Accounts payable and accrued liabilities | 23.8 | |
Asset retirement obligations | 10.8 | 0.3 |
Other long-term liabilities | 136.8 | |
Total liabilities associated with assets held for sale | $ 171.4 | $ 0.3 |
INVENTORY (Schedule of Inventor
INVENTORY (Schedule of Inventory) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
INVENTORY [Abstract] | ||
Natural gas held in storage | $ 418 | $ 133.9 |
Materials and supplies | 53.3 | 32.3 |
Renewable energy credits and emission compliance instruments | 38.2 | 28.4 |
Other inventory | 6.4 | 6.5 |
Total inventory | $ 515.9 | $ 201.1 |
PROPERTY, PLANT AND EQUIPMENT_2
PROPERTY, PLANT AND EQUIPMENT (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
PROPERTY, PLANT AND EQUIPMENT [Abstract] | ||
Interest capitalized | $ 12.6 | $ 10.8 |
Capital projects under construction | 872.7 | 269.5 |
Depreciation expense | $ 324.3 | $ 239.7 |
PROPERTY, PLANT AND EQUIPMENT_3
PROPERTY, PLANT AND EQUIPMENT (Schedule of Property, Plant and Equipment) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment, Reclassified to assets held for sale (note 5), Cost | $ (2,999.3) | $ (16.7) |
Property, plant and equipment, Cost | 11,952.7 | 7,970.8 |
Property, plant and equipment, Reclassified to assets held for sale (note 5), Accumulated amortization | 1,809.7 | 11.4 |
Property, plant and equipment, Accumulated amortization | (1,023.1) | (1,281) |
Property, plant and equipment, Reclassified to assets held for sale (note 5), Net book value | (1,189.6) | (5.3) |
Property, plant and equipment, Net book value | 10,929.6 | 6,689.8 |
Utilities [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment before reclassifications, Cost | 7,090.5 | 2,245.4 |
Property, plant and equipment before reclassifications, Accumulated amortization | (89.7) | (226.1) |
Property, plant and equipment before reclassifications, Net book value | 7,000.8 | 2,019.3 |
Midstream [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment before reclassifications, Cost | 3,178.2 | 2,801.4 |
Property, plant and equipment before reclassifications, Accumulated amortization | (845.7) | (636.3) |
Property, plant and equipment before reclassifications, Net book value | 2,332.5 | 2,165.1 |
Power [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment before reclassifications, Cost | 4,633.9 | 2,874.8 |
Property, plant and equipment before reclassifications, Accumulated amortization | (1,858.3) | (392.3) |
Property, plant and equipment before reclassifications, Net book value | 2,775.6 | 2,482.5 |
Corporate [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment before reclassifications, Cost | 49.4 | 65.9 |
Property, plant and equipment before reclassifications, Accumulated amortization | (39.1) | (37.7) |
Property, plant and equipment before reclassifications, Net book value | $ 10.3 | $ 28.2 |
INTANGIBLE ASSETS (Narrative) (
INTANGIBLE ASSETS (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | ||
Amortization expense | $ 69.7 | $ 42.7 |
Assets excluded from asset base subject to amortization | $ 196.4 | $ 11.2 |
INTANGIBLE ASSETS (Summary of I
INTANGIBLE ASSETS (Summary of Intangible Assets) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets, Reclassified to assets held for sale (note 5), Cost | $ (277.4) | $ (0.1) |
Intangible assets, Cost | 841.4 | 785 |
Intangible assets, reclassified to assets held for sale (note 5), Accumulated amortization | 28.7 | |
Intangible assets, Accumulated amortization | (129.5) | (196.2) |
Intangible assets, Reclassified to assets held for sale (note 5), Net book value | (248.7) | (0.1) |
Intangible assets, Net book value | 711.9 | 588.8 |
Extraction And Transmission (E&T) Contracts [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 26.6 | 26.6 |
Intangible assets before reclassifications, Accumulated amortization | (14.3) | (13.4) |
Intangible assets before reclassifications, Net book value | 12.3 | 13.2 |
Electricity Service Agreements [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 269.5 | 603.1 |
Intangible assets before reclassifications, Accumulated amortization | (25.9) | (108.5) |
Intangible assets before reclassifications, Net book value | 243.6 | 494.6 |
Energy Services Relationships [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 176.1 | 10.2 |
Intangible assets before reclassifications, Accumulated amortization | (33.8) | (8.1) |
Intangible assets before reclassifications, Net book value | 142.3 | 2.1 |
Software [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 293.9 | 126.8 |
Intangible assets before reclassifications, Accumulated amortization | (77.7) | (61.6) |
Intangible assets before reclassifications, Net book value | 216.2 | 65.2 |
Land Rights [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 1.4 | 11 |
Intangible assets before reclassifications, Accumulated amortization | (0.2) | (2.4) |
Intangible assets before reclassifications, Net book value | 1.2 | 8.6 |
Commodity Contract [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 346.3 | |
Intangible assets before reclassifications, Accumulated amortization | (6.3) | |
Intangible assets before reclassifications, Net book value | 340 | |
Franchise And Consents [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets before reclassifications, Cost | 5 | 7.4 |
Intangible assets before reclassifications, Accumulated amortization | (2.2) | |
Intangible assets before reclassifications, Net book value | $ 5 | $ 5.2 |
INTANGIBLE ASSETS (Summary of E
INTANGIBLE ASSETS (Summary of Estimated Amortization Expense of Intangible Assets) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | |
2,019 | $ 84.2 |
2,020 | 82.5 |
2,021 | 57.6 |
2,022 | 132.3 |
2,023 | 38.3 |
Thereafter | $ 120.6 |
GOODWILL (Schedule of Goodwill)
GOODWILL (Schedule of Goodwill) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract] | ||
Balance, beginning of year | $ 817.3 | $ 856 |
Provisions on assets (notes 5 and 10) | (124.2) | |
Business acquisition (note 3) | 3,196.4 | |
Foreign exchange translation | 178.7 | (38.4) |
Reclassified to assets held for sale | (0.3) | |
Balance, end of year | $ 4,068.2 | $ 817.3 |
PROVISIONS ON ASSETS (Narrative
PROVISIONS ON ASSETS (Narrative) (Details) - CAD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |
Nov. 30, 2018 | Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | |
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | $ 728.7 | $ 139.6 | ||
Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 381.3 | 133 | ||
Midstream [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 153.7 | 6.6 | ||
Utilities [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | $ 193.7 | 193.7 | ||
Held-For-Sale [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 9.8 | |||
Held-For-Sale [Member] | Midstream [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 117.2 | 6.6 | ||
Sale of Minority Interest and Other Dispositions [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | $ 340.6 | |||
Shut-In Assets [Member] | Midstream [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 36.5 | |||
Intangible Assets [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 119.3 | |||
Intangible Assets [Member] | Midstream [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 0.5 | |||
Property, Plant and Equipment [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 221.3 | |||
Property, Plant and Equipment [Member] | Midstream [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 148.1 | |||
Property, Plant and Equipment [Member] | Utilities [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 74.6 | |||
Goodwill [Member] | Midstream [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 5.1 | |||
Goodwill [Member] | Utilities [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | $ 119.1 | |||
Development Projects [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 23.1 | |||
Natural Gas-Fired Co-Generation Facility [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 1.8 | |||
Financing Receivable [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | $ 6 | |||
California And Alberta [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 133 | |||
California And Alberta [Member] | Intangible Assets [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | 48.5 | |||
California And Alberta [Member] | Property, Plant and Equipment [Member] | Power [Member] | ||||
Provisions On Assets Disclosure [Line Items] | ||||
Provisions on assets | $ 84.5 |
PROVISIONS ON ASSETS (Schedule
PROVISIONS ON ASSETS (Schedule of Provisions on Assets) (Details) - CAD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | |
Provisions On Assets Disclosure [Line Items] | |||
Provisions on assets | $ 728.7 | $ 139.6 | |
Power [Member] | |||
Provisions On Assets Disclosure [Line Items] | |||
Provisions on assets | 381.3 | 133 | |
Midstream [Member] | |||
Provisions On Assets Disclosure [Line Items] | |||
Provisions on assets | 153.7 | $ 6.6 | |
Utilities [Member] | |||
Provisions On Assets Disclosure [Line Items] | |||
Provisions on assets | $ 193.7 | $ 193.7 |
LONG-TERM INVESTMENTS AND OTH_3
LONG-TERM INVESTMENTS AND OTHER ASSETS (Narrative) (Details) shares in Millions, $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($)shares | |
Number of shares of investment sold | shares | 43.7 |
Proceeds from sale of investment | $ 76.5 |
Loss on Sale of Investments | 2 |
Tidewater Midstream and Infrastructure Inc. [Member] | |
Proceeds from sale of investment | $ 63.4 |
LONG-TERM INVESTMENTS AND OTH_4
LONG-TERM INVESTMENTS AND OTHER ASSETS (Schedule of Long-Term and Other Investments) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
LONG-TERM INVESTMENTS AND OTHER ASSETS [Abstract] | ||
Investments in publicly traded entities | $ 8.4 | $ 95 |
Loan to affiliate (note 30) | 45 | 75 |
Deferred lease receivable | 24.4 | 29 |
Debt issuance costs associated with credit facilities | 7.9 | 20.3 |
Refundable deposits | 16.2 | 14.9 |
Prepayment on long-term service agreements | 82.5 | 68.1 |
Prepaid post-retirement benefits (note 28) | 341.4 | |
Subscription receipts issuance costs | 1.7 | |
Contract asset (note 23) | 11.5 | |
Rabbi trust (note 28) | 61.7 | |
Other | 25.5 | 8.6 |
Long-term investments and other assets | $ 283.1 | $ 312.6 |
VARIABLE INTEREST ENTITIES (Nar
VARIABLE INTEREST ENTITIES (Narrative) (Details) $ in Millions | Jun. 22, 2018 | Jan. 31, 2019CAD ($) | Dec. 31, 2018USD ($)mi | Dec. 31, 2018CAD ($)mi | Dec. 31, 2017CAD ($) |
Variable Interest Entity [Line Items] | |||||
Proceeds from noncontrolling interests, excluding contributed surplus | $ 20,000,000 | ||||
Proceeds from sale of non-controlling interests | $ 908,600,000 | 24,100,000 | |||
Proceeds from non-controlling interest recorded as contributed surplus | 3,000,000 | ||||
Equity method investment | 2,392,400,000 | 567,000,000 | |||
Rile LP [Member] | Minimum [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Estimated project costs | 450,000,000 | ||||
Rile LP [Member] | Maximum [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Estimated project costs | $ 500,000,000 | ||||
Northwest Hydro Facilities [Member] | |||||
Variable Interest Entity [Line Items] | |||||
VIE interest sold | 35.00% | ||||
Proceeds from noncontrolling interests, excluding contributed surplus | 420,400,000 | ||||
Proceeds from sale of non-controlling interests | 921,600,000 | ||||
Proceeds from non-controlling interest recorded as contributed surplus | 334,600,000 | ||||
Northwest Hydro Facilities [Member] | Subsequent Event [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Proceeds from sale of non-controlling interests | $ 1,370,000,000 | ||||
Indirect interest percentage | 55.00% | ||||
Meade Pipeline Co LLC [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Equity method investment | $ 666,900,000 | ||||
Equity Method Investment, Ownership Percentage | 55.00% | ||||
Share of construction costs | $ 446 | ||||
Central Penn [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Indirect interest percentage | 21.00% | 21.00% | |||
Natural Gas Transported, Per Day | 1.7 | ||||
Expected Pipeline Length | mi | 185 | 185 | |||
AltaGas LPG [Member] | Rile LP [Member] | |||||
Variable Interest Entity [Line Items] | |||||
VIE ownership percentage | 70.00% | ||||
AltaGas LPG [Member] | Vopak [Member] | |||||
Variable Interest Entity [Line Items] | |||||
VIE ownership percentage | 30.00% |
VARIABLE INTEREST ENTITIES (Sch
VARIABLE INTEREST ENTITIES (Schedule of VIE Amounts in Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Variable Interest Entity [Line Items] | ||
Current assets | $ 4,033 | $ 701.9 |
Property, plant and equipment | 10,929.6 | 6,689.8 |
Long-term investments and other assets | 283.1 | 312.6 |
Current liabilities | (4,102) | (815.2) |
Asset retirement obligations | (500.6) | (88.3) |
Deferred tax credits | (957.9) | (441.4) |
Variable Interest Entity, Primary Beneficiary [Member] | ||
Variable Interest Entity [Line Items] | ||
Current assets | 1,383.5 | 1.4 |
Property, plant and equipment | 619.2 | 84.3 |
Long-term investments and other assets | 48 | 48 |
Current liabilities | (161.8) | |
Asset retirement obligations | (0.9) | |
Deferred tax credits | (3) | |
Net assets | $ 1,885 | $ 133.7 |
INVESTMENTS ACCOUNTED FOR BY _2
INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Narrative) (Details) $ / shares in Units, $ in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018USD ($)mi | Dec. 31, 2018CAD ($)itemmi$ / shares | Dec. 31, 2017CAD ($) | Dec. 31, 2016CAD ($)shares | Apr. 30, 2018 | |
Schedule of Equity Method Investments [Line Items] | |||||
Investment in affiliate | $ 235.4 | $ 16.8 | |||
Equity income (loss) | 47.9 | 31.4 | |||
Equity Method Investments | 2,392.4 | 567 | |||
Provision on equity method investments | $ 14.5 | 0 | |||
Petrogas [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 33.333% | ||||
Equity income (loss) | $ 12.8 | 12.8 | |||
Petrogas [Member] | Redeemable Convertible Preferred Stock [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Number of shares owned | shares | 6,000,000 | ||||
Dividend rate | 8.50% | 8.50% | |||
EQM [Member] | WGL Holdings [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 5.00% | ||||
ACI [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Share Price | $ / shares | $ 14.50 | ||||
Interest in hydro facility percent | 10.00% | ||||
Canada [Member] | Petrogas [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Investment in affiliate | $ 150 | ||||
Equity income (loss) | $ 12.8 | 12.8 | |||
Equity Method Investments | 150 | 150 | |||
Canada [Member] | Tidewater [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity income (loss) | 1.7 | ||||
Equity Method Investments | |||||
Canada [Member] | AIJVLP [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 50.00% | ||||
Equity income (loss) | $ 2.1 | 6.6 | |||
Equity Method Investments | $ 342.9 | $ 323.3 | |||
Canada [Member] | Inuvik Gas Ltd [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 33.333% | ||||
Equity income (loss) | $ (0.2) | ||||
Equity Method Investments | |||||
Canada [Member] | ACI [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 36.75% | ||||
Equity income (loss) | $ 5.4 | ||||
Equity Method Investments | $ 112.5 | ||||
United States [Member] | Mountain Valley Pipeline LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 10.00% | ||||
Investment in affiliate | $ 350 | ||||
Equity income (loss) | $ 11.5 | ||||
Natural Gas Transported, Per Day | item | 2 | ||||
Expected Pipeline Length | mi | 300 | 300 | |||
Equity Method Investments | $ 532.5 | ||||
United States [Member] | Stonewall Gas Gathering Systems LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 30.00% | ||||
Equity income (loss) | $ 11.8 | ||||
Natural Gas Transported, Per Day | item | 1.4 | ||||
Equity Method Investments | $ 411.8 | ||||
United States [Member] | Constitution [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity method investment, ownership interest | 10.00% | ||||
Equity income (loss) | $ (0.2) | ||||
Equity Method Investments |
INVESTMENTS ACCOUNTED FOR BY _3
INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Schedule of Equity Method Investments) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment | $ 2,392.4 | $ 567 |
Equity income (loss) | $ 47.9 | 31.4 |
Petrogas [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 33.333% | |
Equity income (loss) | $ 12.8 | 12.8 |
Canada [Member] | ACI [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 36.75% | |
Equity method investment | $ 112.5 | |
Equity income (loss) | $ 5.4 | |
Canada [Member] | AIJVLP [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 50.00% | |
Equity method investment | $ 342.9 | 323.3 |
Equity income (loss) | $ 2.1 | 6.6 |
Canada [Member] | Inuvik Gas Ltd [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 33.333% | |
Equity method investment | ||
Equity income (loss) | $ (0.2) | |
Canada [Member] | Sarnia Airport Storage Pool LP [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 50.00% | |
Equity method investment | $ 18.7 | 18.8 |
Equity income (loss) | 1 | 1 |
Canada [Member] | Petrogas [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment | 150 | 150 |
Equity income (loss) | 12.8 | 12.8 |
Canada [Member] | Tidewater [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment | ||
Equity income (loss) | 1.7 | |
United States [Member] | Constitution [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 10.00% | |
Equity method investment | ||
Equity income (loss) | $ (0.2) | |
United States [Member] | Craven County Wood Energy LP [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 50.00% | |
Equity method investment | $ 7.8 | 20.9 |
Equity income (loss) | $ (14.1) | 3.3 |
United States [Member] | Eaton Rapids Gas Storage System [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 50.00% | |
Equity method investment | $ 29.4 | 26.4 |
Equity income (loss) | $ 2 | 2.5 |
United States [Member] | Grayling Generating Station LP [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 50.00% | |
Equity method investment | $ 29 | 27.6 |
Equity income (loss) | $ 3.6 | $ 3.5 |
United States [Member] | Meade Pipeline Co LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 55.00% | |
Equity method investment | $ 757.8 | |
Equity income (loss) | $ 12.2 | |
United States [Member] | Mountain Valley Pipeline LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 10.00% | |
Equity method investment | $ 532.5 | |
Equity income (loss) | $ 11.5 | |
United States [Member] | Stonewall Gas Gathering Systems LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investment, ownership interest | 30.00% | |
Equity method investment | $ 411.8 | |
Equity income (loss) | $ 11.8 |
INVESTMENTS ACCOUNTED FOR BY _4
INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Schedule of Combined Financial Information of Equity Method Investments) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD [Abstract] | ||
Revenues | $ 351.6 | $ 110.6 |
Expenses | (142.7) | (74.2) |
Gross profit | 208.9 | 36.4 |
Current assets | 1,204.6 | 24.8 |
Property, plant and equipment | 7,602.5 | 82.8 |
Intangible assets | 22.9 | 5.6 |
Long-term investments and other assets | 1,326.6 | 843.3 |
Current liabilities | (1,015.2) | (41.7) |
Other long-term liabilities | $ (949.6) | $ (189.1) |
SHORT-TERM DEBT (Narrative) (De
SHORT-TERM DEBT (Narrative) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | |
Short-term Debt [Line Items] | |||
Commercial Paper | $ 1,145.2 | ||
Project Financing | 64.5 | ||
Unsecured Demand Revolving Operating Credit Facility [Member] | Parent Company [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | 70 | $ 50 | |
WGL And Washington Gas [Member] | |||
Short-term Debt [Line Items] | |||
Commercial Paper | $ 839.5 | ||
Letter of Credit [Member] | Unsecured Demand Revolving Operating Credit Facility [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | 35 | ||
Amount outstanding | 6 | ||
Letter of Credit [Member] | Unsecured Extendible Revolving Facility [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | 150 | 150 | |
Amount outstanding | 117 | 40.8 | |
Term | 4 years | ||
Letter of Credit [Member] | Unsecured Bilateral Demand Facility [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | $ 200 | 150 | |
Amount outstanding | $ 147.3 | $ 71.3 | |
Letter of Credit [Member] | Unsecured Extendible Revolving Facility II [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | 300 | ||
Letter of Credit [Member] | WGL Holdings [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | 650 | ||
Amount outstanding | 0 | ||
Letter of Credit [Member] | Washington Gas [Member] | |||
Short-term Debt [Line Items] | |||
Credit facility maximum borrowing capacity | 350 | ||
Amount outstanding | $ 0 |
SHORT-TERM DEBT (Schedule of Sh
SHORT-TERM DEBT (Schedule of Short-Term Debt) (Details) $ in Millions, $ in Millions | Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD ($) |
Short-term Debt [Line Items] | ||||
Bank indebtedness | $ 0.2 | $ 6.2 | ||
Commercial paper | 1,145.2 | |||
Project financing | 64.5 | |||
Short-term debt | 1,209.9 | 46.8 | ||
US Operating Facility [Member] | ||||
Short-term Debt [Line Items] | ||||
Operating facility | 31.7 | |||
Credit facility maximum borrowing capacity | $ 150 | $ 150 | ||
US Operating Facility [Member] | Letter of Credit [Member] | ||||
Short-term Debt [Line Items] | ||||
Operating facility | 0.7 | 0.6 | ||
Domestic Operating Facility [Member | ||||
Short-term Debt [Line Items] | ||||
Operating facility | $ 8.9 | |||
Credit facility maximum borrowing capacity | $ 25 | |||
Prime Rate [Member] | ||||
Short-term Debt [Line Items] | ||||
Effective rate | 3.95% | 3.95% | 3.20% | 3.20% |
LONG-TERM DEBT (Schedule of Lon
LONG-TERM DEBT (Schedule of Long-Term Debt) (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | |
Debt Instrument [Line Items] | |||
Fair value adjustment on WGL Acquisition (note 3) | $ 89,000,000 | ||
Long-term debt, gross | 8,992,300,000 | $ 3,639,800,000 | |
Less debt issuance costs | (35,200,000) | (14,400,000) | |
Total long-term debt | 8,957,100,000 | 3,625,400,000 | |
Less current portion | (890,200,000) | (188,900,000) | |
Long-term debt, noncurrent | 8,066,900,000 | 3,436,500,000 | |
Debenture Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debentures amount sold | 33,300,000 | ||
$1,400 million unsecured extendible revolving [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | May 15, 2023 | ||
Long-term debt, gross | 964,700,000 | 219,100,000 | |
Debt face amount | 1,400,000,000 | ||
US$300 million unsecured extendible revolving [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | May 15, 2022 | ||
Long-term debt, gross | 287,800,000 | ||
Debt face amount | $ 300,000,000 | ||
Acquisition credit facility [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jan. 6, 2020 | ||
Long-term debt, gross | 113,200,000 | ||
US$1,200 million revolving credit facility [Member] | Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Dec. 28, 2021 | ||
Long-term debt, gross | 1,637,000,000 | ||
Debt face amount | $ 1,200,000,000 | ||
$175 million Senior unsecured - 4.60 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jan. 15, 2018 | ||
Long-term debt, gross | 175,000,000 | ||
Debt face amount | $ 175,000,000 | ||
Debt instrument rate | 4.60% | 4.60% | |
$200 million Senior unsecured - 4.55 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jan. 17, 2019 | ||
Long-term debt, gross | $ 200,000,000 | 200,000,000 | |
Debt face amount | $ 200,000,000 | ||
Debt instrument rate | 4.55% | 4.55% | |
$200 million Senior unsecured - 4.07 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jun. 1, 2020 | ||
Long-term debt, gross | $ 200,000,000 | 200,000,000 | |
Debt face amount | $ 200,000,000 | ||
Debt instrument rate | 4.07% | 4.07% | |
$350 million Senior unsecured - 3.72 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Sep. 28, 2021 | ||
Long-term debt, gross | $ 350,000,000 | 350,000,000 | |
Debt face amount | $ 350,000,000 | ||
Debt instrument rate | 3.72% | 3.72% | |
$300 million Senior unsecured - 3.57 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jun. 12, 2023 | ||
Long-term debt, gross | $ 300,000,000 | 300,000,000 | |
Debt face amount | $ 300,000,000 | ||
Debt instrument rate | 3.57% | 3.57% | |
$200 million Senior unsecured - 4.40 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Mar. 15, 2024 | ||
Long-term debt, gross | $ 200,000,000 | 200,000,000 | |
Debt face amount | $ 200,000,000 | ||
Debt instrument rate | 4.40% | 4.40% | |
$300 million Senior unsecured - 3.84 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jan. 15, 2025 | ||
Long-term debt, gross | $ 299,900,000 | 299,900,000 | |
Debt face amount | $ 300,000,000 | ||
Debt instrument rate | 3.84% | 3.84% | |
$100 million Senior unsecured - 5.16 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jan. 13, 2044 | ||
Long-term debt, gross | $ 100,000,000 | 100,000,000 | |
Debt face amount | $ 100,000,000 | ||
Debt instrument rate | 5.16% | 5.16% | |
$300 million Senior unsecured - 4.50 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Aug. 15, 2044 | ||
Long-term debt, gross | $ 299,800,000 | 299,800,000 | |
Debt face amount | $ 300,000,000 | ||
Debt instrument rate | 4.50% | 4.50% | |
$350 million Senior unsecured - 4.12 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Apr. 7, 2026 | ||
Long-term debt, gross | $ 349,800,000 | 349,800,000 | |
Debt face amount | $ 350,000,000 | ||
Debt instrument rate | 4.12% | 4.12% | |
$200 million Senior unsecured - 3.98 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Oct. 4, 2027 | ||
Long-term debt, gross | $ 199,900,000 | 199,900,000 | |
Debt face amount | $ 200,000,000 | ||
Debt instrument rate | 3.98% | 3.98% | |
$250 million Senior unsecured - 4.99 percent [Member] | Medium-term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Oct. 4, 2047 | ||
Long-term debt, gross | $ 250,000,000 | 250,000,000 | |
Debt face amount | $ 250,000,000 | ||
Debt instrument rate | 4.99% | 4.99% | |
US$300 million SEMCO Senior secured - 5.15 percent [Member] | Long-Term Debt [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Apr. 21, 2020 | ||
Long-term debt, gross | $ 409,300,000 | 376,400,000 | |
Debt face amount | $ 300,000,000 | ||
Debt instrument rate | 5.15% | 5.15% | |
US$82 million CINGSA Senior secured - 4.48 percent [Member] | Long-Term Debt [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Mar. 2, 2032 | ||
Long-term debt, gross | $ 86,300,000 | 85,200,000 | |
Debt face amount | $ 82,000,000 | ||
Debt instrument rate | 4.48% | 4.48% | |
PNG 2018 Series Debenture - 8.75 percent [Member] | Debenture Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Nov. 15, 2018 | ||
Long-term debt, gross | 7,000,000 | ||
Debt instrument rate | 8.75% | 8.75% | |
PNG 2025 Series Debenture - 9.30 percent [Member] | Debenture Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jul. 18, 2025 | ||
Long-term debt, gross | 13,000,000 | ||
Debt instrument rate | 9.30% | 9.30% | |
PNG 2027 Series Debenture - 6.90 percent [Member] | Debenture Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Dec. 2, 2027 | ||
Long-term debt, gross | 14,000,000 | ||
Debt instrument rate | 6.90% | 6.90% | |
CINGSA capital lease - 3.50 percent [Member] | Debenture Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | May 1, 2040 | ||
Long-term debt, gross | $ 600,000 | 500,000 | |
Debt instrument rate | 3.50% | 3.50% | |
CINGSA capital lease - 4.48 percent [Member] | Debenture Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jun. 4, 2068 | ||
Long-term debt, gross | $ 200,000 | $ 200,000 | |
Debt instrument rate | 4.48% | 4.48% | |
US$500 million Senior unsecured - 2.25 to 4.76 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date range | Jan - Nov 2019 | ||
Long-term debt, gross | $ 682,100,000 | ||
Debt face amount | $ 500,000,000 | ||
US$250 million Senior unsecured - 2.88 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Mar. 12, 2020 | ||
Long-term debt, gross | $ 341,100,000 | ||
Debt face amount | $ 250,000,000 | ||
Debt instrument rate | 2.88% | 2.88% | |
US$20 million Senior unsecured - 6.65 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Mar. 20, 2023 | ||
Long-term debt, gross | $ 27,300,000 | ||
Debt face amount | $ 20,000,000 | ||
Debt instrument rate | 6.65% | 6.65% | |
US$40.5 million Senior unsecured - 5.44 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Aug. 11, 2025 | ||
Long-term debt, gross | $ 55,300,000 | ||
Debt face amount | $ 40,500,000 | ||
Debt instrument rate | 5.44% | 5.44% | |
US$53 million Senior unsecured - 6.62 to 6.82 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Oct. 1, 2026 | ||
Long-term debt, gross | $ 72,300,000 | ||
Debt face amount | $ 53,000,000 | ||
US$72 million Senior unsecured - 6.40 to 6.57 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date range | Feb - Sep 2027 | ||
Long-term debt, gross | 98,200,000 | ||
Debt face amount | $ 72,000,000 | ||
US$52 million Senior unsecured - 6.57 to 6.85 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date range | Jan - Mar 2028 | ||
Long-term debt, gross | 70,900,000 | ||
Debt face amount | $ 52,000,000 | ||
US$8.5 million Senior unsecured - 7.50 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Apr. 1, 2030 | ||
Long-term debt, gross | $ 11,600,000 | ||
Debt face amount | $ 8,500,000 | ||
Debt instrument rate | 7.50% | 7.50% | |
US$50 million Senior unsecured - 5.70 to 5.78 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date range | Jan - Mar 2036 | ||
Long-term debt, gross | $ 68,200,000 | ||
Debt face amount | $ 50,000,000 | ||
US$75 million Senior unsecured - 5.21 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Dec. 3, 2040 | ||
Long-term debt, gross | $ 102,300,000 | ||
Debt face amount | $ 75,000,000 | ||
Debt instrument rate | 5.21% | 5.21% | |
US$75 million Senior unsecured - 5.00 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Dec. 15, 2043 | ||
Long-term debt, gross | $ 102,300,000 | ||
Debt face amount | $ 75,000,000 | ||
Debt instrument rate | 5.00% | 5.00% | |
US$300 million Senior unsecured - 4.22 to 4.60 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date range | Sep - Dec 2044 | ||
Long-term debt, gross | $ 409,300,000 | ||
Debt face amount | $ 300,000,000 | ||
US$450 million Senior unsecured - 3.80 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Sep. 15, 2046 | ||
Long-term debt, gross | $ 613,900,000 | ||
Debt face amount | $ 450,000,000 | ||
Debt instrument rate | 3.80% | 3.80% | |
Minimum [Member] | US$500 million Senior unsecured - 2.25 to 4.76 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 2.25% | 2.25% | |
Minimum [Member] | US$53 million Senior unsecured - 6.62 to 6.82 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 6.62% | 6.62% | |
Minimum [Member] | US$72 million Senior unsecured - 6.40 to 6.57 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 6.40% | 6.40% | |
Minimum [Member] | US$52 million Senior unsecured - 6.57 to 6.85 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 6.57% | 6.57% | |
Minimum [Member] | US$50 million Senior unsecured - 5.70 to 5.78 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 5.70% | 5.70% | |
Minimum [Member] | US$300 million Senior unsecured - 4.22 to 4.60 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 4.22% | 4.22% | |
Maximum [Member] | US$500 million Senior unsecured - 2.25 to 4.76 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 4.76% | 4.76% | |
Maximum [Member] | US$53 million Senior unsecured - 6.62 to 6.82 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 6.82% | 6.82% | |
Maximum [Member] | US$72 million Senior unsecured - 6.40 to 6.57 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 6.57% | 6.57% | |
Maximum [Member] | US$52 million Senior unsecured - 6.57 to 6.85 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 6.85% | 6.85% | |
Maximum [Member] | US$50 million Senior unsecured - 5.70 to 5.78 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 5.78% | 5.78% | |
Maximum [Member] | US$300 million Senior unsecured - 4.22 to 4.60 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument rate | 4.60% | 4.60% |
ASSET RETIREMENT OBLIGATIONS (N
ASSET RETIREMENT OBLIGATIONS (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligations [Line Items] | ||
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation | $ 770 | $ 232.9 |
Legally restricted assets | $ 0 | |
Minimum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Discount rate for asset retirement obligations | 1.50% | |
Year of expected discount rate application | 2,019 | |
Maximum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Discount rate for asset retirement obligations | 8.50% | |
Year of expected discount rate application | 2,064 |
ASSET RETIREMENT OBLIGATIONS (S
ASSET RETIREMENT OBLIGATIONS (Schedule of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
ASSET RETIREMENT OBLIGATIONS [Abstract] | ||
Balance, beginning of year | $ 88.3 | $ 81.6 |
Obligations acquired (note 3) | 399.1 | |
New obligations | 3.3 | 1.5 |
Obligations settled | (4.2) | (4) |
Disposals | (1.6) | |
Revision in estimated cash flow | 3.8 | 6 |
Accretion expense | 12.3 | 4.4 |
Foreign exchange translation | 20.3 | (0.9) |
Reclassified to liabilities associated with assets held for sale (note 5) | (10.8) | (0.3) |
Total | 510.5 | 88.3 |
Less current portion (included in accounts payable and accrued liabilities) | (9.9) | |
Balance, end of year | $ 500.6 | $ 88.3 |
ENVIRONMENTAL MATTERS (Details)
ENVIRONMENTAL MATTERS (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)item | Dec. 31, 2017CAD ($) | |
Site Contingency [Line Items] | ||
Identified operated manufactured gas plants | item | 12 | |
Accrual for environmental loss contingencies | $ 15.4 | |
Regulatory Assets | 19.9 | $ 13.9 |
Maximum [Member] | ||
Site Contingency [Line Items] | ||
Accrual for environmental loss contingencies | $ 40.1 |
OTHER LONG-TERM LIABILITIES (Sc
OTHER LONG-TERM LIABILITIES (Schedule of Other Long-Term Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Other Long-Term Liabilities [Line Items] | ||
Deferred lease payable | $ 13.1 | $ 2.4 |
Deferred revenue | 3.9 | 3.8 |
Customer advances for construction | 58.6 | 40.9 |
NTL liability | 142 | |
Lease inducement | 2.7 | 3.1 |
Merger commitments | 21.4 | |
Other long term liabilities | 20.3 | 5.7 |
Other long-term liabilities | 122 | 201.9 |
Power purchase agreement termination, settlement amount | 2 | $ 4 |
ASTC [Member] | ||
Other Long-Term Liabilities [Line Items] | ||
Power purchase agreement termination, settlement amount | 6 | |
Accounts Payable and Accrued Liabilities [Member] | ASTC [Member] | ||
Other Long-Term Liabilities [Line Items] | ||
Power purchase agreement termination, settlement amount | $ 2 |
INCOME TAXES (Narrative) (Detai
INCOME TAXES (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Taxes [Line Items] | ||
Statutory income tax rate | 27.00% | 27.00% |
Tax-affected non-capital losses | $ 392.1 | |
Internal Revenue Service (IRS) [Member] | ||
Income Taxes [Line Items] | ||
Statutory income tax rate | 21.00% | 35.00% |
Minimum [Member] | ||
Income Taxes [Line Items] | ||
Tax-affected non-capital losses, expiration date | Dec. 31, 2023 | |
Maximum [Member] | ||
Income Taxes [Line Items] | ||
Tax-affected non-capital losses, expiration date | Dec. 31, 2038 |
INCOME TAXES (Schedule of Incom
INCOME TAXES (Schedule of Income Tax Provision) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
INCOME TAXES [Abstract] | ||
Income (loss) before income taxes - consolidated | $ (716.9) | $ 66.4 |
Statutory income tax rate (%) | 27.00% | 27.00% |
Expected taxes at statutory rates | $ (193.6) | $ 17.9 |
Permanent differences | (1) | 9.5 |
Statutory and other rate differences | (19.6) | (30.5) |
Rate adjustment for change in tax rates | 1.3 | (34.1) |
Deferred income tax recovery on regulated assets | (7.3) | (7.4) |
Tax differences on divestitures and transactions | (32.3) | 6.9 |
Non-controlling interests | 4.7 | |
Change in valuation allowance | (22.3) | 4.2 |
Other | 6.9 | |
Income tax expense, total | (263.2) | (33.5) |
Canada | 23.7 | 18 |
United States | 0.7 | 12.5 |
Current income tax provision | 24.4 | 30.5 |
Canada | (166.1) | (7.4) |
United States | (121.5) | (56.6) |
Deferred income tax expense | $ (287.6) | $ (64) |
Effective income tax rate | 36.70% | (50.50%) |
INCOME TAXES (Schedule of Defer
INCOME TAXES (Schedule of Deferred Income Tax Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
INCOME TAXES [Abstract] | ||
PP&E and intangible assets | $ 1,764.6 | $ 726.5 |
Regulatory assets | (166.3) | |
Regulatory liabilities | 22.8 | |
Tax pools, deferred financing and compensation | (453.6) | (302.3) |
Other | (209.9) | (59.3) |
Valuation allowance | 23.1 | 53.7 |
Net deferred income tax liabilities | $ 957.9 | $ 441.4 |
INCOME TAXES (Schedule of Uncer
INCOME TAXES (Schedule of Uncertain Tax Positions) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
INCOME TAXES [Abstract] | ||
Balance, beginning of year | $ 5.9 | $ 2.2 |
Net changes during the year | (3.7) | 3.7 |
Balance, end of year | $ 2.2 | $ 5.9 |
REGULATORY ASSETS AND LIABILI_3
REGULATORY ASSETS AND LIABILITIES (Schedule of Regulatory Assets and Liabilities) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2018CAD ($) | |
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - current | $ 1.1 | $ 21 | |
Regulatory assets - non-current | 328.6 | 663 | |
Regulatory liabilities - current | 10.9 | 114.9 | |
Regulatory liabilities - non-current | $ 268.6 | 1,392.8 | |
Fair Value Adjustment On Acquisition | 89 | ||
Statutory income tax rate | 27.00% | 27.00% | |
Internal Revenue Service (IRS) [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Statutory income tax rate | 21.00% | 35.00% | |
Deferred Cost Of Gas [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - current | $ 9 | 71.2 | |
Option Fees Deferral [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - non-current | 4.3 | ||
Refundable Tax Credit [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - current | 1.9 | 3.8 | |
Regulatory liabilities - non-current | 7.5 | 6.1 | |
Gas storage facility tax credit | $ 15 | ||
Future Recovery Of Pension And Other Retirement Benefits [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - non-current | 166.7 | ||
Future Removal And Site Restoration Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - non-current | 153.3 | 514.7 | |
Deferred Loss On Reacquired Debt [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - non-current | 1.8 | ||
Federal Income Tax Rate Change [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - current | 26.2 | ||
Regulatory liabilities - non-current | 101.8 | 698.4 | |
Insurance Recovery Of Environmental Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - non-current | 0.3 | ||
Regulatory liabilities, Recovery Period | 2 years | ||
Other [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities - current | 13.7 | ||
Regulatory liabilities - non-current | 1.4 | 5.1 | |
Deferred Cost Of Gas [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - current | 0.5 | 20.4 | |
Deferred Property Taxes [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - current | 0.3 | ||
Deferred Regulatory Costs And Rate Stabilization Adjustment Mechanism [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 20.5 | 215.5 | |
Pipeline Rehabilitation Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 0.3 | ||
Future Recovery Of Pension And Other Retirement Benefits [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 113.9 | 192.9 | |
Future Recovery Of Non-Retirement Employee Benefits [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 21.3 | ||
Deferred Pension Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 7.8 | ||
Regulatory assets, Recovery Period | 1 year | ||
Deferred Environmental Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 13.9 | 19.9 | |
Deferred Loss On Reacquired Debt [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 2.5 | 109.3 | |
Deferred Depreciation And Amortization [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 23.3 | ||
Deferred Future Income Taxes [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 104.7 | 67 | |
Deferred Customer Retention Program Amortization [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 16.5 | ||
Revenue Deficiency Account [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - non-current | 31 | ||
Other [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets - current | 0.3 | 0.6 | |
Regulatory assets - non-current | $ 2 | $ 29.3 | |
CINGSA [Member] | Refundable Tax Credit [Member] | 2012 Through 2021 [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Annual disbursement rate of tax credit | 10.00% | ||
Minimum [Member] | Future Removal And Site Restoration Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities, Recovery Period | 3 years | ||
Minimum [Member] | Deferred Regulatory Costs And Rate Stabilization Adjustment Mechanism [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 1 year | ||
Minimum [Member] | Deferred Environmental Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 1 year | ||
Minimum [Member] | Deferred Loss On Reacquired Debt [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 1 year | ||
Maximum [Member] | Deferred Cost Of Gas [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities, Recovery Period | 1 year | ||
Maximum [Member] | Refundable Tax Credit [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities, Recovery Period | 1 year | ||
Maximum [Member] | Future Removal And Site Restoration Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities, Recovery Period | 56 years | ||
Maximum [Member] | Federal Income Tax Rate Change [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities, Recovery Period | 1 year | ||
Maximum [Member] | Other [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities, Recovery Period | 1 year | ||
Maximum [Member] | Deferred Cost Of Gas [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 1 year | ||
Maximum [Member] | Deferred Property Taxes [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 1 year | ||
Maximum [Member] | Deferred Regulatory Costs And Rate Stabilization Adjustment Mechanism [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 3 years | ||
Maximum [Member] | Deferred Environmental Costs [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 10 years | ||
Maximum [Member] | Deferred Loss On Reacquired Debt [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 15 years | ||
Maximum [Member] | Other [Member] | |||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets, Recovery Period | 1 year |
ACCUMULATED OTHER COMPREHENSI_3
ACCUMULATED OTHER COMPREHENSIVE INCOME (Schedule of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | $ 4,639.2 | |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | 379.9 | $ (206) |
Ending balance | 7,640.2 | 4,639.2 |
Available-For-Sale [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | (7.1) | 19.8 |
OCI before reclassification | (30.3) | |
Adoption Of ASU No. 2016-01 (note 2) | 7.1 | |
Current period OCI (pre-tax) | 7.1 | (30.3) |
Income tax on amounts retained in AOCI | 3.4 | |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | 7.1 | (26.9) |
Ending balance | (7.1) | |
Defined Benefit Pension And PRB Plans [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | (11.4) | (11.3) |
OCI before reclassification | (14.1) | (1.3) |
Amounts reclassified from OCI | 0.7 | 1.3 |
Curtailment of DB and PRB plan | 4.2 | |
Current period OCI (pre-tax) | (9.2) | |
Income tax on amounts retained in AOCI | 3.3 | 0.3 |
Income tax on amounts reclassified to earnings | (0.2) | (0.4) |
Income tax on amounts related to curtailment of DB and PRB plan | (1.5) | |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | (7.6) | (0.1) |
Ending balance | (19) | (11.4) |
Hedge Net investments [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | (129) | (135.6) |
OCI before reclassification | (90.6) | 6.6 |
Current period OCI (pre-tax) | (90.6) | 6.6 |
Income tax on amounts retained in AOCI | 10.4 | |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | (80.2) | 6.6 |
Ending balance | (209.2) | (129) |
Translation Foreign Operations [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | 342.9 | 526.3 |
OCI before reclassification | 458.5 | (183.4) |
Current period OCI (pre-tax) | 458.5 | (183.4) |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | 458.5 | (183.4) |
Ending balance | 801.4 | 342.9 |
Equity Investee [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | 3.7 | 5.9 |
OCI before reclassification | 2.1 | (2.2) |
Current period OCI (pre-tax) | 2.1 | (2.2) |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | 2.1 | (2.2) |
Ending balance | 5.8 | 3.7 |
Accumulated Other Comprehensive Income [Member] | ||
Accumulated Other Comprehensive Income Loss [Line Items] | ||
Opening balance | 199.1 | 405.1 |
OCI before reclassification | 355.9 | (210.6) |
Amounts reclassified from OCI | 0.7 | 1.3 |
Adoption Of ASU No. 2016-01 (note 2) | 7.1 | |
Curtailment of DB and PRB plan | 4.2 | |
Current period OCI (pre-tax) | 367.9 | (209.3) |
Income tax on amounts retained in AOCI | 13.7 | 3.7 |
Income tax on amounts reclassified to earnings | (0.2) | (0.4) |
Income tax on amounts related to curtailment of DB and PRB plan | (1.5) | |
Total other comprehensive income (loss) (OCI), net of taxes (note 21) | 379.9 | (206) |
Ending balance | $ 579 | $ 199.1 |
ACCUMULATED OTHER COMPREHENSI_4
ACCUMULATED OTHER COMPREHENSIVE INCOME (Summary of Reclassification from Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Operating and administrative expense | $ 1,129 | $ 572.2 |
Deferred income tax recovery (note 19) | (287.6) | (64) |
Net income (loss) | (435.1) | 91.6 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Deferred income tax recovery (note 19) | (0.2) | (0.4) |
Net income (loss) | 0.5 | 0.9 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Defined Benefit Pension And PRB Plans [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Operating and administrative expense | $ 0.7 | $ 1.3 |
FINANCIAL INSTRUMENTS AND FIN_3
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGMENT (Narrative) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2018USD ($)contract | Dec. 31, 2018CAD ($)contract | Jun. 30, 2018CAD ($) | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Unrealized gains (losses) on risk management contracts | $ 80.8 | $ (62.5) | |||
Customer Concentration Risk [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Concentration risk | 0.00% | ||||
Foreign Exchange Forward [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Derivative notional amount | $ 3,200 | ||||
Derivative, Gain on Derivative | $ 1.3 | ||||
Interest Rate Swap [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Fixed rate debt, percent | 59.00% | 59.00% | |||
Number of instruments | contract | 0 | 0 | |||
Foreign Exchange Option [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Derivative, Loss on Derivative | 36 | ||||
Weather Related Derivative [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Unrealized gains (losses) on risk management contracts | (1) | ||||
Currency, U.S. Dollar [Member] | Net Investment Hedge [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Gain (loss) on translation, net of tax | 80.2 | 6.6 | |||
Outstanding amount of hedge | $ 1,494 | ||||
Currency, U.S. Dollar [Member] | Foreign Exchange Option [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Derivative notional amount | $ 1,200 | ||||
Unrealized gains (losses) on risk management contracts | $ 34.3 | $ (34.3) |
FINANCIAL INSTRUMENTS AND FIN_4
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Fair Value of Risk Management Assets and Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | $ 114.1 | $ 38.6 |
Risk management assets - non-current | 57.7 | 15.9 |
Risk management liabilities - current | 89.3 | 57.6 |
Risk management liabilities - non-current | 213 | 13.8 |
Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Equity securities | 8.4 | 95 |
Loans and receivables | 45 | 75 |
Financial assets | 225.2 | 224.5 |
Current portion of long-term debt | 890.2 | 188.9 |
Long-term debt | 8,066.9 | 3,436.5 |
Other current liabilities | 11.2 | 22.4 |
Other long-term liabilities | 2 | 146 |
Financial liabilities | 9,272.6 | 3,865.2 |
Carrying Amount [Member] | Fair Value Through Net Income [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 99 | 38.6 |
Risk management assets - non-current | 49 | 15.9 |
Risk management liabilities - current | 72 | 57.6 |
Risk management liabilities - non-current | 103.4 | 13.8 |
Carrying Amount [Member] | Fair Value Through Regulatory Assets/Liabilities [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 15.1 | |
Risk management assets - non-current | 8.7 | |
Risk management liabilities - current | 17.3 | |
Risk management liabilities - non-current | 109.6 | |
Fair Value [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Equity securities | 8.4 | 95 |
Loans and receivables | 45.2 | 85.6 |
Financial assets | 225.4 | 235.1 |
Current portion of long-term debt | 884.4 | 189.6 |
Long-term debt | 8,040.3 | 3,568.3 |
Other current liabilities | 11.2 | 22.4 |
Other long-term liabilities | 2 | 147.7 |
Financial liabilities | 9,240.2 | 3,999.4 |
Fair Value [Member] | Fair Value Through Net Income [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 99 | 38.6 |
Risk management assets - non-current | 49 | 15.9 |
Risk management liabilities - current | 72 | 57.6 |
Risk management liabilities - non-current | 103.4 | 13.8 |
Fair Value [Member] | Fair Value Through Regulatory Assets/Liabilities [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 15.1 | |
Risk management assets - non-current | 8.7 | |
Risk management liabilities - current | 17.3 | |
Risk management liabilities - non-current | 109.6 | |
Fair Value [Member] | Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Equity securities | 8.4 | 95 |
Financial assets | 8.4 | 95 |
Fair Value [Member] | Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Loans and receivables | 45.2 | 85.6 |
Financial assets | 134.2 | 140.1 |
Current portion of long-term debt | 884.4 | 189.6 |
Long-term debt | 6,027.6 | 3,568.3 |
Other current liabilities | 11.2 | 22.4 |
Other long-term liabilities | 2 | 147.7 |
Financial liabilities | 6,984.8 | 3,999.4 |
Fair Value [Member] | Level 2 [Member] | Fair Value Through Net Income [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 68.3 | 38.6 |
Risk management assets - non-current | 18 | 15.9 |
Risk management liabilities - current | 41.3 | 57.6 |
Risk management liabilities - non-current | 15.3 | $ 13.8 |
Fair Value [Member] | Level 2 [Member] | Fair Value Through Regulatory Assets/Liabilities [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 2.7 | |
Risk management liabilities - current | 2.9 | |
Risk management liabilities - non-current | 0.1 | |
Fair Value [Member] | Level 3 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets | 82.8 | |
Long-term debt | 2,012.7 | |
Financial liabilities | 2,255.4 | |
Fair Value [Member] | Level 3 [Member] | Fair Value Through Net Income [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 30.7 | |
Risk management assets - non-current | 31 | |
Risk management liabilities - current | 30.7 | |
Risk management liabilities - non-current | 88.1 | |
Fair Value [Member] | Level 3 [Member] | Fair Value Through Regulatory Assets/Liabilities [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Risk management assets - current | 12.4 | |
Risk management assets - non-current | 8.7 | |
Risk management liabilities - current | 14.4 | |
Risk management liabilities - non-current | $ 109.5 |
FINANCIAL INSTRUMENTS AND FIN_5
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Quantitative Information About The Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($)$ / item | |
Natural Gas [Member] | Valuation Technique, Discounted Cash Flow [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability) | $ | $ (144.1) |
Natural Gas [Member] | Valuation Technique, Option Pricing Model [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability) | $ | (4.4) |
Electricity [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability) | $ | $ (14.7) |
Minimum [Member] | Natural Gas [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Percent | 37.46% |
Minimum [Member] | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Per Dekatherm | (1.40) |
Minimum [Member] | Natural Gas [Member] | Valuation Technique, Option Pricing Model [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Per Dekatherm | (1.37) |
Minimum [Member] | Electricity [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Per Megawatt Hour | 8.28 |
Maximum [Member] | Natural Gas [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Percent | 900.98% |
Maximum [Member] | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Per Dekatherm | 7.28 |
Maximum [Member] | Natural Gas [Member] | Valuation Technique, Option Pricing Model [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Per Dekatherm | 5.07 |
Maximum [Member] | Electricity [Member] | |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | |
Fair Value, Net Asset (Liability), Per Megawatt Hour | 84.44 |
FINANCIAL INSTRUMENTS AND FIN_6
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Balance, beginning of year | ||
Acquired (note 3) | (146.7) | |
Recorded in income | (14.8) | |
Recorded in regulatory assets | (5.9) | |
Transfers out of Level 3 | 7.3 | |
Purchases | 6.4 | |
Settlements | (3.1) | |
Foreign exchange translation | (6.4) | |
Balance, end of year | (163.2) | |
Natural Gas [Member] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Balance, beginning of year | ||
Acquired (note 3) | (136.1) | |
Recorded in income | (8.3) | |
Recorded in regulatory assets | (5.9) | |
Transfers out of Level 3 | 7.3 | |
Purchases | ||
Settlements | 0.3 | |
Foreign exchange translation | (5.8) | |
Balance, end of year | (148.5) | |
Electricity [Member] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Balance, beginning of year | ||
Acquired (note 3) | (10.6) | |
Recorded in income | (6.5) | |
Recorded in regulatory assets | ||
Transfers out of Level 3 | ||
Purchases | 6.4 | |
Settlements | (3.4) | |
Foreign exchange translation | (0.6) | |
Balance, end of year | $ (14.7) |
FINANCIAL INSTRUMENTS AND FIN_7
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Realized and Unrealized Losses Recorded to Income for Level 3 Measurements) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements | $ (14.8) |
Commodity Contract [Member] | Recorded to Revenue [Member] | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements | (11.1) |
Commodity Contract [Member] | Recorded to Cost of Sales [Member] | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements | $ (3.7) |
FINANCIAL INSTRUMENTS AND FIN_8
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Summary of Unrealized Gains (Losses) on Risk Management Contracts) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative Instruments Gain Loss [Line Items] | ||
Unrealized gains (losses) on risk management contracts | $ 80.8 | $ (62.5) |
Natural Gas Contracts [Member] | ||
Derivative Instruments Gain Loss [Line Items] | ||
Unrealized gains (losses) on risk management contracts | (2.2) | 2.2 |
Storage Optimization [Member] | ||
Derivative Instruments Gain Loss [Line Items] | ||
Unrealized gains (losses) on risk management contracts | 2.7 | |
NGL Frac Spread [Member] | ||
Derivative Instruments Gain Loss [Line Items] | ||
Unrealized gains (losses) on risk management contracts | 40 | (11.7) |
Power Contracts [Member] | ||
Derivative Instruments Gain Loss [Line Items] | ||
Unrealized gains (losses) on risk management contracts | 9.3 | (20.8) |
Foreign Exchange [Member] | ||
Derivative Instruments Gain Loss [Line Items] | ||
Unrealized gains (losses) on risk management contracts | $ 33.7 | $ (34.9) |
FINANCIAL INSTRUMENTS AND FIN_9
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Offsetting Assets and Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Offsetting Assets And Liabilities [Line Items] | ||
Gross amount of recognized assets | $ 262.3 | $ 61.7 |
Gross amount of liabilities offset in balance sheet | (90.5) | (7.2) |
Net amount of assets presented in balance sheet | 171.8 | 54.5 |
Gross amounts of recognized liabilities | 394.9 | 74.4 |
Gross amount of assets offset in balance sheet | (90.5) | (7.2) |
Netting of collateral | (2.1) | 4.2 |
Net amount of liabilities presented in balance sheet | 302.3 | 71.4 |
Risk management assets - current | 114.1 | 38.6 |
Risk management assets - non-current | 57.7 | 15.9 |
Risk management liabilities - current | 89.3 | 57.6 |
Risk management liabilities - non-current | 213 | 13.8 |
Natural Gas Contracts [Member] | ||
Offsetting Assets And Liabilities [Line Items] | ||
Gross amount of recognized assets | 200.8 | 41 |
Gross amount of liabilities offset in balance sheet | (82) | (6.2) |
Net amount of assets presented in balance sheet | 118.8 | 34.8 |
Gross amounts of recognized liabilities | 340.4 | 35.1 |
Gross amount of assets offset in balance sheet | (82) | (6.2) |
Netting of collateral | (3.3) | |
Net amount of liabilities presented in balance sheet | 255.1 | 28.9 |
NGL Frac Spread [Member] | ||
Offsetting Assets And Liabilities [Line Items] | ||
Gross amount of recognized assets | 18.7 | 1.3 |
Gross amount of liabilities offset in balance sheet | (0.7) | (0.3) |
Net amount of assets presented in balance sheet | 18 | 1 |
Gross amounts of recognized liabilities | 2.7 | 25.3 |
Gross amount of assets offset in balance sheet | (0.7) | (0.3) |
Net amount of liabilities presented in balance sheet | 2 | 25 |
Power Contracts [Member] | ||
Offsetting Assets And Liabilities [Line Items] | ||
Gross amount of recognized assets | 42.8 | 17.7 |
Gross amount of liabilities offset in balance sheet | (7.8) | (0.7) |
Net amount of assets presented in balance sheet | 35 | 17 |
Gross amounts of recognized liabilities | 50.6 | 14 |
Gross amount of assets offset in balance sheet | (7.8) | (0.7) |
Netting of collateral | 1.2 | 4.2 |
Net amount of liabilities presented in balance sheet | 44 | 17.5 |
Foreign Exchange [Member] | ||
Offsetting Assets And Liabilities [Line Items] | ||
Gross amount of recognized assets | 1.7 | |
Net amount of assets presented in balance sheet | $ 1.7 | |
Gross amounts of recognized liabilities | 1.2 | |
Net amount of liabilities presented in balance sheet | $ 1.2 |
FINANCIAL INSTRUMENTS AND FI_10
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Collateral Not Offset Against Risk Management Assets and Liabilities) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT [Abstract] | |
Collateral posted with counterparties | $ 27.6 |
Cash collateral held representing an obligation | $ 0.8 |
FINANCIAL INSTRUMENTS AND FI_11
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Risk Management Liabilities And Maximum Potential Collateral Requirements) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT [Abstract] | |
Risk management liabilities with credit-risk-contingent features | $ 14.7 |
Maximum potential collateral requirements | $ 7.5 |
FINANCIAL INSTRUMENTS AND FI_12
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Fixed and Market Price Contract) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)MWhkJ$ / item$ / bbl$ / kJ$ / MWhbbl | Dec. 31, 2017CAD ($)MWhkJ$ / item$ / bbl$ / kJ$ / MWhbbl | |
Natural Gas Contracts [Member] | Sales [Member] | ||
Derivative [Line Items] | ||
Notional volume (GJ or MWh) | kJ | 858,640,810,000 | 94,804,039,000 |
Fair Value ($) | $ 19 | $ 14.8 |
Natural Gas Contracts [Member] | Purchases [Member] | ||
Derivative [Line Items] | ||
Notional volume (GJ or MWh) | kJ | 1,638,207,391,000 | 61,980,315,000 |
Fair Value ($) | $ (179.5) | $ (16.8) |
Natural Gas Contracts [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Notional volume (GJ or MWh) | kJ | 621,578,572,000 | 6,039,641,000 |
Fair Value ($) | $ 20.9 | $ 7.9 |
Natural Gas Contracts [Member] | Minimum [Member] | Sales [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / kJ | 1,070 | 420 |
Period (months) | 1 month | 1 month |
Natural Gas Contracts [Member] | Minimum [Member] | Purchases [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / kJ | 690 | 520 |
Period (months) | 1 month | 1 month |
Natural Gas Contracts [Member] | Minimum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / kJ | 2,560 | 2,860 |
Period (months) | 1 month | 1 month |
Natural Gas Contracts [Member] | Maximum [Member] | Sales [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / kJ | 12,190 | 6,890 |
Period (months) | 178 months | 60 months |
Natural Gas Contracts [Member] | Maximum [Member] | Purchases [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / kJ | 16,260 | 6,400 |
Period (months) | 179 months | 48 months |
Natural Gas Contracts [Member] | Maximum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / kJ | 15,370 | 9,380 |
Period (months) | 231 months | 10 months |
Power Contracts [Member] | Sales [Member] | ||
Derivative [Line Items] | ||
Notional volume (GJ or MWh) | MWh | 11,881,575 | 2,169,321 |
Fair Value ($) | $ (1.9) | $ (2.5) |
Power Contracts [Member] | Purchases [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | 58.50 | |
Notional volume (GJ or MWh) | MWh | 8,507,874 | 17,520 |
Fair Value ($) | $ 16.4 | $ (4.5) |
Power Contracts [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Notional volume (GJ or MWh) | MWh | 20,957,180 | 1,563,160 |
Fair Value ($) | $ (22.3) | $ 6.5 |
Power Contracts [Member] | Minimum [Member] | Sales [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | 26.90 | 38.20 |
Period (months) | 1 month | 1 month |
Power Contracts [Member] | Minimum [Member] | Purchases [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | 25.50 | |
Period (months) | 1 month | 1 month |
Power Contracts [Member] | Minimum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | (6.07) | 37.50 |
Period (months) | 1 month | 1 month |
Power Contracts [Member] | Maximum [Member] | Sales [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | 95.03 | 95.03 |
Period (months) | 60 months | 60 months |
Power Contracts [Member] | Maximum [Member] | Purchases [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | 50.25 | |
Period (months) | 36 months | 12 months |
Power Contracts [Member] | Maximum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / MWh | 76.18 | 63.50 |
Period (months) | 48 months | 48 months |
Propane [Member] | NGL Frac Spread [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Notional volume (Bbl) | bbl | 1,725,114 | 1,992,927 |
Fair Value ($) | $ 12.6 | $ (10.9) |
Propane [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / bbl | 38.89 | 28.77 |
Period (months) | 1 month | 1 month |
Propane [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / bbl | 47.63 | 49.21 |
Period (months) | 12 months | 12 months |
Butane [Member] | NGL Frac Spread [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Notional volume (Bbl) | bbl | 74,371 | 130,088 |
Fair Value ($) | $ 1.2 | $ (0.3) |
Butane [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / bbl | 52.95 | 47.83 |
Period (months) | 1 month | 1 month |
Butane [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / bbl | 55.26 | 54.67 |
Period (months) | 12 months | 12 months |
Crude Oil [Member] | NGL Frac Spread [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Notional volume (Bbl) | bbl | 329,230 | 518,665 |
Fair Value ($) | $ 6 | $ (4.4) |
Crude Oil [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / bbl | 79.64 | 61.05 |
Period (months) | 1 month | 1 month |
Crude Oil [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / bbl | 86.28 | 75.64 |
Period (months) | 12 months | 12 months |
Natural Gas [Member] | NGL Frac Spread [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Notional volume (GJ or MWh) | kJ | 9,490,365,000 | 11,428,515,000 |
Fair Value ($) | $ (3.8) | $ (8.4) |
Natural Gas [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / item | 1.38 | 0.42 |
Period (months) | 1 month | 1 month |
Natural Gas [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member] | ||
Derivative [Line Items] | ||
Fixed price | $ / item | 1.68 | 2.27 |
Period (months) | 12 months | 12 months |
FINANCIAL INSTRUMENTS AND FI_13
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)$ / item$ / item$ / bbl$ / MWh | Dec. 31, 2017CAD ($) | |
Derivative [Line Items] | ||
Unrealized gains (losses) on risk management contracts | $ 80.8 | $ (62.5) |
Alberta Power Price [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, energy | $ / MWh | 1 | |
Unrealized gains (losses) on risk management contracts | $ 0.3 | |
PJM Power Price [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, energy | $ / item | 1 | |
Unrealized gains (losses) on risk management contracts | $ 1.2 | |
AECO Natural Gas Price [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, energy | $ / item | 0.50 | |
Unrealized gains (losses) on risk management contracts | $ 5.9 | |
NYMEX Natural Gas Price [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, energy | $ / item | 0.50 | |
Unrealized gains (losses) on risk management contracts | $ 31.5 | |
NGL Frac Spread [Member] | ||
Derivative [Line Items] | ||
Unrealized gains (losses) on risk management contracts | $ 40 | $ (11.7) |
NGL Frac Spread [Member] | Propane [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, volume | $ / bbl | 1 | |
Unrealized gains (losses) on risk management contracts | $ 1.7 | |
NGL Frac Spread [Member] | Butane [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, volume | $ / bbl | 1 | |
Unrealized gains (losses) on risk management contracts | $ 0.1 | |
NGL Frac Spread [Member] | WTI Crude Oil [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, volume | $ / bbl | 1 | |
Unrealized gains (losses) on risk management contracts | $ 0.3 | |
NGL Frac Spread [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Increase or decrease to forward prices, energy | $ / item | 0.50 | |
Unrealized gains (losses) on risk management contracts | $ 4.7 |
FINANCIAL INSTRUMENTS AND FI_14
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Accounts Receivable Past Due or Impaired) (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
AR accruals | $ 447.5 | $ 184.6 | ||
Allowance for credit losses | $ (2.4) | $ (2.5) | (54.7) | (2.4) |
Accounts receivable | 1,547.5 | 382.9 | ||
Allowance for credit losses, Balance, beginning of year | 2.4 | 2.5 | ||
Allowance for credit losses, Foreign exchange translation | 0.1 | (0.1) | ||
Allowance for credit losses, New allowance | 53.1 | 0.4 | ||
Allowance for credit losses, Change in allowance | (0.9) | |||
Allowance for credit losses, Allowance applied to uncollectible customer accounts | (0.4) | |||
Allowance for credit losses, Balance, end of year | 54.7 | $ 2.4 | ||
WGL Holdings [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Allowance credit losses acquired | $ 52.9 | |||
Less Than 30 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 189.3 | |||
Accounts receivable | 989 | |||
31 to 60 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 7.9 | |||
Accounts receivable | 74.1 | |||
61 to 90 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 1.4 | |||
Accounts receivable | 12.8 | |||
Over 90 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | (0.3) | |||
Accounts receivable | 24.1 | |||
Trade Accounts Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 1,574.6 | 383 | ||
AR accruals | 447.5 | 184.6 | ||
Receivables impaired | 54.7 | 2.4 | ||
Trade Accounts Receivable [Member] | Less Than 30 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 187 | |||
Accounts receivable | 961.5 | |||
Trade Accounts Receivable [Member] | 31 to 60 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 7.9 | |||
Accounts receivable | 74.1 | |||
Trade Accounts Receivable [Member] | 61 to 90 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 1.4 | |||
Accounts receivable | 12.8 | |||
Trade Accounts Receivable [Member] | Over 90 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | (0.3) | |||
Accounts receivable | 24 | |||
Other Accounts Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | 27.6 | 2.3 | ||
Other Accounts Receivable [Member] | Less Than 30 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable, gross | $ 2.3 | |||
Accounts receivable | 27.5 | |||
Other Accounts Receivable [Member] | Over 90 Days [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | $ 0.1 |
FINANCIAL INSTRUMENTS AND FI_15
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Contractual Maturities for Financial Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative [Line Items] | ||
Contractual maturities, Total | $ 11,938.9 | $ 4,373.7 |
Contractual maturities, Less than 1 year | 3,709.1 | 763 |
Contractual maturities, 1 - 3 years | 3,178.7 | 1,045.9 |
Contractual maturities, 4 - 5 years | 1,625.9 | 387.3 |
Contractual maturities, After 5 years | 3,425.2 | 2,177.5 |
Accounts Payable and Accrued Liabilities [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 1,488.2 | 415.3 |
Contractual maturities, Less than 1 year | 1,488.2 | 415.3 |
Dividends Payable [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 22 | 32 |
Contractual maturities, Less than 1 year | 22 | 32 |
Short-term Debt [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 1,209.9 | 46.8 |
Contractual maturities, Less than 1 year | 1,209.9 | 46.8 |
Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 11.2 | 22.4 |
Contractual maturities, Less than 1 year | 11.2 | 22.4 |
Other Long-Term Liabilities [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 2 | 146 |
Contractual maturities, 1 - 3 years | 2 | 25.7 |
Contractual maturities, 4 - 5 years | 20.8 | |
Contractual maturities, After 5 years | 99.5 | |
Risk Management Contract Liabilities [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 302.3 | 71.4 |
Contractual maturities, Less than 1 year | 89.3 | 57.6 |
Contractual maturities, 1 - 3 years | 113.3 | 11.1 |
Contractual maturities, 4 - 5 years | 33.3 | 2.7 |
Contractual maturities, After 5 years | 66.4 | |
Current Portion Of Long-Term Debt [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 888.5 | 188.9 |
Contractual maturities, Less than 1 year | 888.5 | 188.9 |
Long-Term Debt [Member] | ||
Derivative [Line Items] | ||
Contractual maturities, Total | 8,014.8 | 3,450.9 |
Contractual maturities, 1 - 3 years | 3,063.4 | 1,009.1 |
Contractual maturities, 4 - 5 years | 1,592.6 | 363.8 |
Contractual maturities, After 5 years | $ 3,358.8 | $ 2,078 |
REVENUE (Narrative) (Details)
REVENUE (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Contract with Customer, Asset, Net | $ 11.5 | |
WGL Energy Systems [Member] | ||
Contract with Customer, Asset, Net | 47.3 | |
Provision on assets held for sale | 6 | |
Contract with Customer, Liability | $ 2.2 | |
Utilities [Member] | Gas Storage Services [Member] | ||
Contract with Customer, Duration | 1 year | |
Midstream [Member] | Minimum [Member] | Commodity Sales Contracts [Member] | ||
Contract with Customer, Duration | 1 year | |
Midstream [Member] | Maximum [Member] | Commodity Sales Contracts [Member] | ||
Contract with Customer, Duration | 5 years | |
Power [Member] | Commodity Sales Contracts [Member] | ||
Contract with Customer, Duration | 20 years |
REVENUE (Disaggregation of Reve
REVENUE (Disaggregation of Revenue by Major Sources) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 3,123.8 | |
Other sources of revenue | 1,132.9 | |
Total revenue | 4,256.7 | $ 2,556.2 |
Commodity Sales Contracts [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,162.7 | |
Midstream Service Contracts [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 205 | |
Gas Sales And Transportation Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,684.3 | |
Storage Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 35.4 | |
Other Product And Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 36.4 | |
Revenue From Alternative Revenue Programs [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 21.7 | |
Leasing Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 452.1 | |
Risk Management And Trading Activities [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 644.2 | |
Risk Management And Trading Activities [Member] | GAIL [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue | $ 264.2 | |
Contract with Customer, Duration | 20 years | |
Other Sources Of Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | $ 14.9 | |
Utilities [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,730.4 | |
Other sources of revenue | 22.2 | |
Total revenue | 1,752.6 | |
Utilities [Member] | Gas Sales And Transportation Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,684.3 | |
Utilities [Member] | Storage Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 35.4 | |
Utilities [Member] | Other Product And Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 10.7 | |
Utilities [Member] | Revenue From Alternative Revenue Programs [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 21.7 | |
Utilities [Member] | Leasing Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 0.6 | |
Utilities [Member] | Risk Management And Trading Activities [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 1 | |
Utilities [Member] | Other Sources Of Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | (1.1) | |
Midstream [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 870.8 | |
Other sources of revenue | 473.8 | |
Total revenue | 1,344.6 | |
Midstream [Member] | Commodity Sales Contracts [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 665.2 | |
Midstream [Member] | Midstream Service Contracts [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 205 | |
Midstream [Member] | Other Product And Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 0.6 | |
Midstream [Member] | Leasing Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 96.6 | |
Midstream [Member] | Risk Management And Trading Activities [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 377.6 | |
Midstream [Member] | Other Sources Of Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | (0.4) | |
Power [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 522.6 | |
Other sources of revenue | 639.4 | |
Total revenue | 1,162 | |
Power [Member] | Commodity Sales Contracts [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 497.5 | |
Contract with Customer, Duration | 20 years | |
Power [Member] | Other Product And Services [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 25.1 | |
Power [Member] | Leasing Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 354.9 | |
Power [Member] | Risk Management And Trading Activities [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 268.5 | |
Power [Member] | Other Sources Of Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | 16 | |
Corporate [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | (2.5) | |
Total revenue | (2.5) | |
Corporate [Member] | Risk Management And Trading Activities [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | (2.9) | |
Corporate [Member] | Other Sources Of Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Other sources of revenue | $ 0.4 |
REVENUE (Schedule of Estimated
REVENUE (Schedule of Estimated Revenue Related to Performance Obligations) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Revenue, Remaining Performance Obligation, Amount | $ 934.3 |
2019 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 126.5 |
2020 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 103.1 |
2021 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 70.8 |
2022 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 69.6 |
2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 65.7 |
>2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 498.6 |
Midstream Service Contracts [Member] | |
Revenue, Remaining Performance Obligation, Amount | 392.5 |
Midstream Service Contracts [Member] | 2019 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 52.2 |
Midstream Service Contracts [Member] | 2020 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 55.7 |
Midstream Service Contracts [Member] | 2021 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 32.3 |
Midstream Service Contracts [Member] | 2022 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 31.9 |
Midstream Service Contracts [Member] | 2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 28 |
Midstream Service Contracts [Member] | >2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 192.4 |
Gas Sales And Transportation Services [Member] | |
Revenue, Remaining Performance Obligation, Amount | 6.2 |
Gas Sales And Transportation Services [Member] | 2019 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.6 |
Gas Sales And Transportation Services [Member] | 2020 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.6 |
Gas Sales And Transportation Services [Member] | 2021 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.6 |
Gas Sales And Transportation Services [Member] | 2022 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.6 |
Gas Sales And Transportation Services [Member] | 2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.6 |
Gas Sales And Transportation Services [Member] | >2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 3.2 |
Storage Services [Member] | |
Revenue, Remaining Performance Obligation, Amount | 481.7 |
Storage Services [Member] | 2019 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 36.7 |
Storage Services [Member] | 2020 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 36.3 |
Storage Services [Member] | 2021 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 36.3 |
Storage Services [Member] | 2022 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 36.3 |
Storage Services [Member] | 2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 36.3 |
Storage Services [Member] | >2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 299.8 |
Other [Member] | |
Revenue, Remaining Performance Obligation, Amount | 53.9 |
Other [Member] | 2019 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 37 |
Other [Member] | 2020 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 10.5 |
Other [Member] | 2021 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 1.6 |
Other [Member] | 2022 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.8 |
Other [Member] | 2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | 0.8 |
Other [Member] | >2023 [Member] | |
Revenue, Remaining Performance Obligation, Amount | $ 3.2 |
SHAREHOLDERS' EQUITY (Narrative
SHAREHOLDERS' EQUITY (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Common shares outstanding | 275,200,000 | 175,300,000 | |
Proceeds from issuance of shares | $ 2,633.7 | $ 236.3 | |
Dividend reinvestment discount rate | 3.00% | ||
Dividend reinvestment cash purchase price, percentage | 101.00% | ||
Average market price measurement period | 10 days | ||
Share Option Plan [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Shares reserved for issuance | 21,213,224 | ||
Unexpensed fair value of share option compensation cost | $ 3.7 | 1.3 | |
Aggregate intrinsic value of options exercisable | 6 | ||
Intrinsic value of options outstanding | 6 | ||
Intrinsic value of options exercised | $ 0.3 | 1.4 | |
Share Option Plan [Member] | Minimum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Options term | 6 years | ||
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period | 6 years | ||
Share Option Plan [Member] | Maximum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Options term | 10 years | ||
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period | 10 years | ||
Vesting period | 4 years | ||
Mid-Term Incentive Plan [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Unrecognized compensation expense | $ 26.9 | 8.4 | |
Mid-Term Incentive Plan [Member] | Minimum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 36 months | ||
Mid-Term Incentive Plan [Member] | Maximum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 44 months | ||
Mid-Term Incentive And Deferred Share Unit Plans [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Compensation expense | $ 16.6 | $ 9.1 | |
Common Stock [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Common shares outstanding | 275,224,066 | 175,279,216 | 166,906,833 |
Cumulative Preferred Stock [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Preferred stock authorized, percentage of voting rights | 50.00% |
SHAREHOLDERS' EQUITY (Schedule
SHAREHOLDERS' EQUITY (Schedule of Common Shares Issued and Outstanding) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Class of Stock [Line Items] | ||
Common Shares Issued and Outstanding, Beginning balance, Number of shares | 175,300,000 | |
Shares issued for cash on exercise of options, Number of shares | 57,275 | 240,125 |
Common Shares Issued and Outstanding, Ending balance, Number of shares | 275,200,000 | 175,300,000 |
Balance, beginning of year | $ 4,573.4 | |
Balance at end of year | $ 7,019.6 | $ 4,573.4 |
Common Stock [Member] | ||
Class of Stock [Line Items] | ||
Common Shares Issued and Outstanding, Beginning balance, Number of shares | 175,279,216 | 166,906,833 |
Shares issued on conversion of subscription receipts, net of issuance costs, Number of shares | 84,510,000 | |
Shares issued for cash on exercise of options, Number of shares | 57,275 | 240,125 |
Shares issued under DRIP, Number of shares | 15,377,575 | 8,132,258 |
Common Shares Issued and Outstanding, Ending balance, Number of shares | 275,224,066 | 175,279,216 |
Balance, beginning of year | $ 4,007.9 | $ 3,773.4 |
Shares issued on conversion of subscription receipts, net of issuance costs, Amount | 2,305.6 | |
Shares issued for cash on exercise of options, Amount | 1.3 | 6.5 |
Deferred taxes on share issuance cost, Amount | 13.3 | (8.3) |
Shares issued under DRIP, Amount | 325.8 | 236.3 |
Balance at end of year | $ 6,653.9 | $ 4,007.9 |
SHAREHOLDERS' EQUITY (Schedul_2
SHAREHOLDERS' EQUITY (Schedule of Preferred Shares Issued and Outstanding) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Amount | $ 7,019.6 | $ 4,573.4 | |
Fair value adjustment on WGL Acquisition (note 3) | $ 89 | ||
Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 52,280,600 | 52,000,000 | |
Preferred Shares Issued and Outstanding, Amount | $ 1,318.8 | $ 1,277.7 | $ 985.1 |
Fair value adjustment on WGL Acquisition (note 3) | 4.1 | ||
Share issuance costs, net of taxes | $ (27.9) | $ (27.9) | |
Series A [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 5,511,220 | 5,511,220 | |
Preferred Shares Issued and Outstanding, Amount | $ 137.8 | $ 137.8 | |
Series B [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 2,488,780 | 2,488,780 | |
Preferred Shares Issued and Outstanding, Amount | $ 62.2 | $ 62.2 | |
Series C [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 8,000,000 | 8,000,000 | |
Preferred Shares Issued and Outstanding, Amount | $ 205.6 | $ 205.6 | |
Series E [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 8,000,000 | 8,000,000 | |
Preferred Shares Issued and Outstanding, Amount | $ 200 | $ 200 | |
Series G [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 8,000,000 | 8,000,000 | |
Preferred Shares Issued and Outstanding, Amount | $ 200 | $ 200 | |
Series I [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 8,000,000 | 8,000,000 | |
Preferred Shares Issued and Outstanding, Amount | $ 200 | $ 200 | |
Series K [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 12,000,000 | 12,000,000 | |
Preferred Shares Issued and Outstanding, Amount | $ 300 | $ 300 | |
$4.80 Series [Member] | Cumulative Preferred Stock [Member] | Washington Gas [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 150,000 | ||
Preferred Shares Issued and Outstanding, Amount | $ 19.7 | ||
$4.25 Series [Member] | Cumulative Preferred Stock [Member] | Washington Gas [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 70,600 | ||
Preferred Shares Issued and Outstanding, Amount | $ 9.4 | ||
$5.00 Series [Member] | Cumulative Preferred Stock [Member] | Washington Gas [Member] | |||
Class of Stock [Line Items] | |||
Preferred Shares Issued and Outstanding, Number of shares | 60,000 | ||
Preferred Shares Issued and Outstanding, Amount | $ 7.9 |
SHAREHOLDERS' EQUITY (Summary o
SHAREHOLDERS' EQUITY (Summary of Cumulative Redeemable Preferred Shares) (Details) - 12 months ended Dec. 31, 2018 | $ / sharesshares | $ / shares$ / sharesshares | $ / sharesshares |
Series A [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 3.38% | 3.38% | |
Annual dividend per share | $ 0.845 | ||
Redemption price per share | $ 25 | $ 25 | |
Series A [Member] | Five-Year Government Of Canada Bond [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 2.66% | 2.66% | |
Series B [Member] | |||
Class of Stock [Line Items] | |||
Redemption price per share | $ 25.50 | $ 25.50 | |
Floating quarterly dividend rate | $ 0.26938 | ||
Series B [Member] | 90-Day Government Of Canada Treasury Bill [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 2.66% | 2.66% | |
Series C [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 5.29% | 5.29% | |
Series C [Member] | United States Government Bond Yield [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 3.58% | 3.58% | |
Series C, Redemption Price US$25, Annual Dividend US$1.3225 [Member] | |||
Class of Stock [Line Items] | |||
Annual dividend per share | $ 1.3225 | ||
Redemption price per share | $ 25 | ||
Series E [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 5.393% | 5.393% | |
Annual dividend per share | $ 1.34825 | ||
Redemption price per share | $ 25 | $ 25 | |
Series E [Member] | Five-Year Government Of Canada Bond [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 3.17% | 3.17% | |
Series G [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 4.75% | 4.75% | |
Annual dividend per share | $ 1.1875 | ||
Redemption price per share | $ 25 | $ 25 | |
Series G [Member] | Five-Year Government Of Canada Bond [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 3.06% | 3.06% | |
Series I [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 5.25% | 5.25% | |
Annual dividend per share | $ 1.3125 | ||
Redemption price per share | $ 25 | $ 25 | |
Series I [Member] | Minimum [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 5.25% | 5.25% | |
Series I [Member] | Five-Year Government Of Canada Bond [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 4.19% | 4.19% | |
Series K [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 5.00% | 5.00% | |
Annual dividend per share | $ 1.25 | ||
Redemption price per share | $ 25 | $ 25 | |
Series K [Member] | Minimum [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 5.00% | 5.00% | |
Series K [Member] | Five-Year Government Of Canada Bond [Member] | |||
Class of Stock [Line Items] | |||
Preferred stock dividend rate in addition to variable rate | 3.80% | 3.80% | |
Series D [Member] | |||
Class of Stock [Line Items] | |||
Redemption price per share | $ 25.50 | ||
Shares authorized | shares | 8,000,000 | 8,000,000 | 8,000,000 |
Series F [Member] | |||
Class of Stock [Line Items] | |||
Redemption price per share | $ 25.50 | ||
Shares authorized | shares | 8,000,000 | 8,000,000 | 8,000,000 |
Series H [Member] | |||
Class of Stock [Line Items] | |||
Redemption price per share | $ 25.50 | ||
Shares authorized | shares | 8,000,000 | 8,000,000 | 8,000,000 |
Series J [Member] | |||
Class of Stock [Line Items] | |||
Redemption price per share | $ 25.50 | ||
Shares authorized | shares | 8,000,000 | 8,000,000 | 8,000,000 |
Series L [Member] | |||
Class of Stock [Line Items] | |||
Redemption price per share | $ 25.50 | ||
Shares authorized | shares | 12,000,000 | 12,000,000 | 12,000,000 |
Washington Gas [Member] | $4.80 Series [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 4.27% | 4.27% | |
Annual dividend per share | $ 4.80 | ||
Redemption price per share | $ 101 | $ 101 | |
Washington Gas [Member] | $4.25 Series [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 4.27% | 4.27% | |
Annual dividend per share | $ 4.25 | ||
Redemption price per share | $ 105 | $ 105 | |
Washington Gas [Member] | $5.00 Series [Member] | |||
Class of Stock [Line Items] | |||
Current Yield | 4.27% | 4.27% | |
Annual dividend per share | $ 5 | ||
Redemption price per share | $ 102 | $ 102 |
SHAREHOLDERS' EQUITY (Summary_2
SHAREHOLDERS' EQUITY (Summary of Share Option Activity) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
SHAREHOLDERS' EQUITY [Abstract] | ||
Share options outstanding, beginning of year, Number of options | 4,533,761 | 4,119,386 |
Granted, Number of options | 2,811,460 | 848,000 |
Exercised, Number of options | (57,275) | (240,125) |
Forfeited, Number of options | (878,013) | (193,500) |
Expired, Number of options | (100,750) | |
Share options outstanding, end of year, Number of options | 6,309,183 | 4,533,761 |
Share options exercisable, end of year, Number of options | 2,897,723 | 3,326,197 |
Share options outstanding, beginning of year, Exercise price | $ 32.35 | $ 32.39 |
Granted, Exercise price | 16.69 | 30.80 |
Exercised, Exercise price | 20.68 | 24.63 |
Forfeited, Exercise price | 36.47 | 36.36 |
Expired, Exercise price | 14.60 | |
Share options outstanding, end of year, Exercise price | 25.18 | 32.35 |
Share options exercisable, end of year, Exercise price | $ 32.01 | $ 31.93 |
SHAREHOLDERS' EQUITY (Summary_3
SHAREHOLDERS' EQUITY (Summary of Employee Share Option Plan) (Details) - 12 months ended Dec. 31, 2018 | $ / sharesshares | $ / shares$ / sharesshares |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Options outstanding, Number outstanding | shares | 6,309,183 | 6,309,183 |
Options outstanding, Weighted average exercise price | $ 25.18 | $ 25.18 |
Options outstanding, Weighted average remaining contractual life | 4 years 3 months 4 days | 4 years 3 months 4 days |
Options exercisable, Number exercisable | shares | 2,897,723 | 2,897,723 |
Options exercisable, Weighted average exercise price | $ 32.01 | $ 32.01 |
Options exercisable, Weighted average remaining contractual life | 2 years 9 months 7 days | 2 years 9 months 7 days |
$14.24 to $18.00 [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Options outstanding, Exercise price range, Lower limit | $ 14.24 | |
Options outstanding, Exercise price range, Upper limit | $ 18 | |
Options outstanding, Number outstanding | shares | 2,322,635 | 2,322,635 |
Options outstanding, Weighted average exercise price | $ 14.55 | $ 14.55 |
Options outstanding, Weighted average remaining contractual life | 5 years 10 months 28 days | 5 years 10 months 28 days |
Options exercisable, Number exercisable | shares | 28,000 | 28,000 |
Options exercisable, Weighted average exercise price | $ 17.10 | $ 17.10 |
Options exercisable, Weighted average remaining contractual life | 1 year 3 months 29 days | 1 year 3 months 29 days |
$18.01 to $25.08 [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Options outstanding, Exercise price range, Lower limit | $ 18.01 | |
Options outstanding, Exercise price range, Upper limit | $ 25.08 | |
Options outstanding, Number outstanding | shares | 425,000 | 425,000 |
Options outstanding, Weighted average exercise price | $ 20.76 | $ 20.76 |
Options outstanding, Weighted average remaining contractual life | 1 year 9 months 29 days | 1 year 9 months 29 days |
Options exercisable, Number exercisable | shares | 425,000 | 425,000 |
Options exercisable, Weighted average exercise price | $ 20.76 | $ 20.76 |
Options exercisable, Weighted average remaining contractual life | 1 year 9 months 29 days | 1 year 9 months 29 days |
$25.09 to $50.89 [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Options outstanding, Exercise price range, Lower limit | $ 25.09 | |
Options outstanding, Exercise price range, Upper limit | $ 50.89 | |
Options outstanding, Number outstanding | shares | 3,561,548 | 3,561,548 |
Options outstanding, Weighted average exercise price | $ 32.65 | $ 32.65 |
Options outstanding, Weighted average remaining contractual life | 3 years 5 months 23 days | 3 years 5 months 23 days |
Options exercisable, Number exercisable | shares | 2,444,723 | 2,444,723 |
Options exercisable, Weighted average exercise price | $ 34.14 | $ 34.14 |
Options exercisable, Weighted average remaining contractual life | 2 years 11 months 12 days | 2 years 11 months 12 days |
SHAREHOLDERS' EQUITY (Summary_4
SHAREHOLDERS' EQUITY (Summary of Fair Value Options Granted) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
SHAREHOLDERS' EQUITY [Abstract] | ||
Fair value per option ($) | $ 1.27 | $ 1.91 |
Risk-free interest rate (%) | 1.99% | 1.31% |
Expected life (years) | 6 years | 6 years |
Expected volatility (%) | 23.23% | 21.05% |
Annual dividend per share ($) | $ 1.18 | $ 2.12 |
SHAREHOLDERS' EQUITY (Schedul_3
SHAREHOLDERS' EQUITY (Schedule of MTIP and DSUP Activity) (Details) - shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
SHAREHOLDERS' EQUITY [Abstract] | ||
Balance, beginning of year | 564,549 | 364,839 |
Acquired | 5,291,621 | |
Granted | 9,502,347 | 386,126 |
Additional units added by performance factor | 24,301 | |
Vested and paid out | (148,154) | (221,775) |
Forfeited | (66,522) | (27,279) |
Units in lieu of dividends | 55,934 | 38,337 |
Balance, ending of year | 15,199,775 | 564,549 |
NET INCOME PER COMMON SHARE (Su
NET INCOME PER COMMON SHARE (Summary of Net Income per Common Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
NET INCOME PER COMMON SHARE [Abstract] | ||
Net income (loss) applicable to controlling interests | $ (435.1) | $ 91.6 |
Less: Preferred share dividends | (66.6) | (61.3) |
Net income (loss) applicable to common shares | $ (501.7) | $ 30.3 |
Weighted average number of common shares outstanding | 222.6 | 171 |
Dilutive equity instruments | 0.1 | 0.3 |
Weighted average number of common shares outstanding - diluted | 222.7 | 171.3 |
Basic net income (loss) per common share | $ (2.25) | $ 0.18 |
Diluted net income (loss) per common share | $ (2.25) | $ 0.18 |
Anti-dilutive share options excluded from diluted income per share | 4 | 2.8 |
OTHER INCOME (Schedule of Other
OTHER INCOME (Schedule of Other Income (Loss)) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
OTHER INCOME [Abstract] | ||
Losses from sale of assets | $ (10.6) | $ (2.7) |
Other components of net benefit cost (note 2) | 18.9 | |
Interest income and other revenue | 2.7 | 8.7 |
Gains (losses) on investments | (10.1) | 3.6 |
Total other income (loss) | $ 0.9 | $ 9.6 |
OPERATING LEASES (Narrative) (D
OPERATING LEASES (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Leased Assets [Line Items] | ||
Property, plant and equipment | $ 10,929.6 | $ 6,689.8 |
Operating Leases, Income Statement, Minimum Lease Revenue | 285 | 290.8 |
Revenue from minimum lease payments | 285 | 290.8 |
Revenue from contingent leases | 167.1 | 175.6 |
Assets Leased to Others [Member] | ||
Operating Leased Assets [Line Items] | ||
Property, plant and equipment | $ 2,000 | $ 3,000 |
OPERATING LEASES (Schedule of F
OPERATING LEASES (Schedule of Future Minimum Revenue from Operating Leases) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
OPERATING LEASES [Abstract] | |
2,019 | $ 194.4 |
2,020 | 155.3 |
2,021 | 111.9 |
2,022 | 112 |
2,023 | $ 104.2 |
PENSION PLANS AND RETIREE BEN_3
PENSION PLANS AND RETIREE BENEFITS (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Defined contribution plan cost recorded | $ 15.4 | $ 8.4 |
Rabbi trust | $ 89.3 | |
Year trend rate reaches maximum | 2,024 | |
Minimum [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Plan assets investment objective period | 3 years | |
Assumed initial healthcare cost trend rate | 6.40% | |
Ultimate trend rate | 2.10% | |
Maximum [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Plan assets investment objective period | 5 years | |
Assumed initial healthcare cost trend rate | 6.50% | |
Ultimate trend rate | 5.00% | |
Fixed Income [Member] | Minimum [Member] | Canada [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target asset mix | 45.00% | |
Fixed Income [Member] | Maximum [Member] | SEMCO [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target asset mix | 33.00% | |
Fixed Income [Member] | Maximum [Member] | WGL Holdings [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target asset mix | 55.00% | |
Fixed Income [Member] | Maximum [Member] | Canada [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target asset mix | 55.00% |
PENSION PLANS AND RETIREE BEN_4
PENSION PLANS AND RETIREE BENEFITS (Summary of Defined Benefit Plans) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Plan assets, Fair value, end of year | $ 2,159.1 | |
Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit obligation, Balance, beginning of year | 469.4 | $ 440.5 |
Plans disposed (note 4) | (132.1) | |
Actuarial loss (gain) | (68.5) | 31.5 |
Current service cost | 18.6 | 15.9 |
Member contributions | 0.2 | |
Interest cost | 39.2 | 17.5 |
Benefits paid | (45.9) | (14.9) |
Expenses paid | (0.9) | (1.1) |
Plan combinations | 1,312.4 | |
Foreign exchange translation | 77.4 | (20.2) |
Balance, end of year | 1,669.6 | 469.4 |
Plan assets, Fair value, beginning of year | 363.9 | 328.4 |
Plan disposed (note 4) | (102.1) | |
Actual return on plan assets | (55) | 46.4 |
Employer contributions | 11 | 21.1 |
Member contributions | 0.2 | |
Benefits paid | (45.9) | (14.9) |
Expenses paid | (0.9) | (1.1) |
Plan combinatinos | 1,133.5 | |
Foreign exchange translation | 63.4 | (16.2) |
Plan assets, Fair value, end of year | 1,367.9 | 363.9 |
Accrued benefit liability | (301.7) | (105.5) |
Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit obligation, Balance, beginning of year | 98.5 | 89.1 |
Plans disposed (note 4) | (13.6) | |
Actuarial loss (gain) | (33.9) | 12.8 |
Current service cost | 5.4 | 2.5 |
Member contributions | 2.1 | |
Interest cost | 11 | 3.5 |
Benefits paid | (13.4) | (3.5) |
Expenses paid | (0.1) | (0.1) |
Plan combinations | 382.9 | |
Plan amendments | (0.4) | |
Plan settlements | (0.5) | |
Foreign exchange translation | 21.4 | (5.3) |
Balance, end of year | 459.9 | 98.5 |
Plan assets, Fair value, beginning of year | 78.9 | 74 |
Plan disposed (note 4) | (8.1) | |
Actual return on plan assets | (37.2) | 11.4 |
Employer contributions | 2.5 | 1.8 |
Member contributions | 2.1 | |
Benefits paid | (13.4) | (3.5) |
Expenses paid | (0.1) | (0.1) |
Plan combinatinos | 732.7 | |
Foreign exchange translation | 33.8 | (4.7) |
Plan assets, Fair value, end of year | 791.2 | 78.9 |
Accrued benefit liability | 331.3 | (19.6) |
Canada [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit obligation, Balance, beginning of year | 165.6 | 150 |
Plans disposed (note 4) | (132.1) | |
Actuarial loss (gain) | (0.8) | 8.3 |
Current service cost | 2.4 | 7.9 |
Member contributions | 0.2 | |
Interest cost | 1.2 | 5.8 |
Benefits paid | (2.7) | (6.3) |
Expenses paid | (0.3) | |
Plan combinations | 0.7 | |
Balance, end of year | 34.3 | 165.6 |
Plan assets, Fair value, beginning of year | 115.2 | 101.5 |
Plan disposed (note 4) | (102.1) | |
Actual return on plan assets | (0.3) | 8.5 |
Employer contributions | 3.4 | 11.6 |
Member contributions | 0.2 | |
Benefits paid | (2.7) | (6.3) |
Expenses paid | (0.3) | |
Plan combinatinos | 0.3 | |
Plan assets, Fair value, end of year | 13.8 | 115.2 |
Accrued benefit liability | (20.5) | (50.4) |
Canada [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit obligation, Balance, beginning of year | 15.8 | 16.4 |
Plans disposed (note 4) | (13.6) | |
Actuarial loss (gain) | (0.1) | (1.6) |
Current service cost | 0.1 | 0.7 |
Interest cost | 0.1 | 0.6 |
Benefits paid | (0.3) | |
Plan amendments | (0.4) | |
Balance, end of year | 1.9 | 15.8 |
Plan assets, Fair value, beginning of year | 8.1 | 6.8 |
Plan disposed (note 4) | (8.1) | |
Actual return on plan assets | 0.4 | |
Employer contributions | 1.2 | |
Benefits paid | (0.3) | |
Plan assets, Fair value, end of year | 8.1 | |
Accrued benefit liability | (1.9) | (7.7) |
United States [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Plan assets, Fair value, end of year | 2,145.3 | |
United States [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit obligation, Balance, beginning of year | 303.8 | 290.5 |
Actuarial loss (gain) | (67.7) | 23.2 |
Current service cost | 16.2 | 8 |
Interest cost | 38 | 11.7 |
Benefits paid | (43.2) | (8.6) |
Expenses paid | (0.9) | (0.8) |
Plan combinations | 1,311.7 | |
Foreign exchange translation | 77.4 | (20.2) |
Balance, end of year | 1,635.3 | 303.8 |
Plan assets, Fair value, beginning of year | 248.7 | 226.9 |
Actual return on plan assets | (54.7) | 37.9 |
Employer contributions | 7.6 | 9.5 |
Benefits paid | (43.2) | (8.6) |
Expenses paid | (0.9) | (0.8) |
Plan combinatinos | 1,133.2 | |
Foreign exchange translation | 63.4 | (16.2) |
Plan assets, Fair value, end of year | 1,354.1 | 248.7 |
Accrued benefit liability | (281.2) | (55.1) |
United States [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit obligation, Balance, beginning of year | 82.7 | 72.7 |
Actuarial loss (gain) | (33.8) | 14.4 |
Current service cost | 5.3 | 1.8 |
Member contributions | 2.1 | |
Interest cost | 10.9 | 2.9 |
Benefits paid | (13.4) | (3.2) |
Expenses paid | (0.1) | (0.1) |
Plan combinations | 382.9 | |
Plan settlements | (0.5) | |
Foreign exchange translation | 21.4 | (5.3) |
Balance, end of year | 458 | 82.7 |
Plan assets, Fair value, beginning of year | 70.8 | 67.2 |
Actual return on plan assets | (37.2) | 11 |
Employer contributions | 2.5 | 0.6 |
Member contributions | 2.1 | |
Benefits paid | (13.4) | (3.2) |
Expenses paid | (0.1) | (0.1) |
Plan combinatinos | 732.7 | |
Foreign exchange translation | 33.8 | (4.7) |
Plan assets, Fair value, end of year | 791.2 | 70.8 |
Accrued benefit liability | $ 333.2 | $ (11.9) |
PENSION PLANS AND RETIREE BEN_5
PENSION PLANS AND RETIREE BENEFITS (Schedule of Amount Included in the Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plan Disclosure [Line Items] | ||
Prepaid post-retirement benefits | $ 341.4 | |
Accounts payable and accrued liabilities | (27.6) | $ (0.6) |
Future employee obligations | (284.2) | (124.5) |
Total amounts included in Consolidated Balance Sheets | 29.6 | (125.1) |
Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accounts payable and accrued liabilities | (27.6) | (0.6) |
Future employee obligations | (273.9) | (104.9) |
Total amounts included in Consolidated Balance Sheets | (301.5) | (105.5) |
Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Prepaid post-retirement benefits | 341.4 | |
Future employee obligations | (10.3) | (19.6) |
Total amounts included in Consolidated Balance Sheets | $ 331.1 | $ (19.6) |
PENSION PLANS AND RETIREE BEN_6
PENSION PLANS AND RETIREE BENEFITS (Schedule of Funded Status Based on Accumulated Benefit Obligation) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Canada [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ (32.9) | $ (143.9) |
Fair value of plan assets | 13.8 | 115.2 |
Funded status | (19.1) | (28.7) |
United States [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | (1,525.6) | (274.2) |
Fair value of plan assets | 1,354.1 | 248.7 |
Funded status | $ (171.5) | $ (25.5) |
PENSION PLANS AND RETIREE BEN_7
PENSION PLANS AND RETIREE BENEFITS (Summary of Amounts Recorded in Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Past service cost | $ (0.5) | $ (0.4) |
Net actuarial loss | (19.4) | (13.9) |
Recognized in AOCI pre-tax | (19.9) | (14.3) |
Increase (decrease) by the amount included in deferred tax liabilities | 4.6 | 3.9 |
Net amount in AOCI after-tax | (15.3) | (10.4) |
Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Past service cost | 0.4 | |
Net actuarial loss | (5.5) | (1.3) |
Recognized in AOCI pre-tax | (5.1) | (1.3) |
Increase (decrease) by the amount included in deferred tax liabilities | 1.4 | 0.3 |
Net amount in AOCI after-tax | (3.7) | (1) |
Canada [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Past service cost | (0.3) | (0.4) |
Net actuarial loss | (8.7) | (13.9) |
Recognized in AOCI pre-tax | (9) | (14.3) |
Increase (decrease) by the amount included in deferred tax liabilities | 2.4 | 4 |
Net amount in AOCI after-tax | (6.6) | (10.3) |
Canada [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Past service cost | 0.4 | |
Net actuarial loss | (0.5) | (1.3) |
Recognized in AOCI pre-tax | (0.1) | (1.3) |
Increase (decrease) by the amount included in deferred tax liabilities | 0.3 | |
Net amount in AOCI after-tax | (0.1) | (1) |
United States [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Past service cost | (0.2) | |
Net actuarial loss | (10.7) | |
Recognized in AOCI pre-tax | (10.9) | |
Increase (decrease) by the amount included in deferred tax liabilities | 2.2 | (0.1) |
Net amount in AOCI after-tax | (8.7) | $ (0.1) |
United States [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial loss | (5) | |
Recognized in AOCI pre-tax | (5) | |
Increase (decrease) by the amount included in deferred tax liabilities | 1.4 | |
Net amount in AOCI after-tax | $ (3.6) |
PENSION PLANS AND RETIREE BEN_8
PENSION PLANS AND RETIREE BENEFITS (Summary of Amounts Recorded in A Regulatory Asset (Liability)) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Prior service cost | $ 0.8 | $ (1.2) |
Net actuarial gain (loss) | 188.2 | (104.6) |
Recognized in regulatory asset (liability) | 189 | (105.8) |
Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Prior service cost | (110.2) | 5.6 |
Net actuarial gain (loss) | (52.6) | (12.4) |
Recognized in regulatory asset (liability) | (162.8) | (6.8) |
Canada [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial gain (loss) | (30.6) | |
Recognized in regulatory asset (liability) | (30.6) | |
Canada [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial gain (loss) | 0.4 | |
Recognized in regulatory asset (liability) | 0.4 | |
United States [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Prior service cost | 0.8 | (1.2) |
Net actuarial gain (loss) | 188.2 | (74) |
Recognized in regulatory asset (liability) | 189 | (75.2) |
United States [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Prior service cost | (110.2) | 5.6 |
Net actuarial gain (loss) | (52.6) | (12.8) |
Recognized in regulatory asset (liability) | $ (162.8) | $ (7.2) |
PENSION PLANS AND RETIREE BEN_9
PENSION PLANS AND RETIREE BENEFITS (Summary of Amounts to be Amortized from AOCI in the Next Fiscal Year) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Defined Benefit Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Past service costs | $ 0.1 |
Actuarial losses | 0.5 |
Total amounts to be amortized in the next fiscal year from AOCI | 0.6 |
Post-Retirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Past service costs | 0.2 |
Actuarial losses | |
Total amounts to be amortized in the next fiscal year from AOCI | $ 0.2 |
PENSION PLANS AND RETIREE BE_10
PENSION PLANS AND RETIREE BENEFITS (Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($) | |
Defined Benefit Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Prior service cost | $ 0.2 |
Actuarial losses | 9.1 |
Total | 9.3 |
Post-Retirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Prior service cost | (21.3) |
Actuarial losses | 0.1 |
Total | $ (21.2) |
PENSION PLANS AND RETIREE BE_11
PENSION PLANS AND RETIREE BENEFITS (Schedule of Net Periodic Benefit Expense) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Settlement (gain) loss | $ (0.2) | |
Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Current service cost | $ 18.6 | 15.9 |
Interest cost | 39.2 | 17.5 |
Expected return on plan assets | (50.4) | (22.8) |
Amortization of past service cost | 0.1 | 0.2 |
Amortization of net actuarial loss | 0.6 | 0.7 |
Amortization of regulatory assets | 7.8 | 7.8 |
Net benefit cost (income) recognized | 15.9 | 19.3 |
Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Current service cost | 5.4 | 2.5 |
Interest cost | 11 | 3.5 |
Expected return on plan assets | (21.6) | (4.9) |
Settlement (gain) loss | 0.2 | |
Amortization of regulatory assets | (11.1) | (0.2) |
Net benefit cost (income) recognized | (16.3) | 1.1 |
Canada [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Current service cost | 2.4 | 7.9 |
Interest cost | 1.2 | 5.8 |
Expected return on plan assets | (0.5) | (5.9) |
Amortization of past service cost | 0.1 | 0.2 |
Amortization of net actuarial loss | 0.6 | 0.7 |
Amortization of regulatory assets | 1.3 | |
Net benefit cost (income) recognized | 3.8 | 10 |
Canada [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Current service cost | 0.1 | 0.7 |
Interest cost | 0.1 | 0.6 |
Expected return on plan assets | (0.2) | |
Amortization of regulatory assets | 0.1 | |
Net benefit cost (income) recognized | 0.2 | 1.2 |
United States [Member] | Defined Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Current service cost | 16.2 | 8 |
Interest cost | 38 | 11.7 |
Expected return on plan assets | (49.9) | (16.9) |
Amortization of regulatory assets | 7.8 | 6.5 |
Net benefit cost (income) recognized | 12.1 | 9.3 |
United States [Member] | Post-Retirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Current service cost | 5.3 | 1.8 |
Interest cost | 10.9 | 2.9 |
Expected return on plan assets | (21.6) | (4.7) |
Settlement (gain) loss | 0.2 | |
Amortization of regulatory assets | (11.1) | (0.3) |
Net benefit cost (income) recognized | $ (16.5) | $ (0.1) |
PENSION PLANS AND RETIREE BE_12
PENSION PLANS AND RETIREE BENEFITS (Schedule of Collective Investment Mixes for Plan Assets) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Total fair value of plan investment | $ 2,159.2 | ||
Net payable | (0.1) | ||
Fair value of Plan Assets | $ 2,159.1 | ||
Percentage of Plan Assets | 100.00% | ||
Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 1,165.7 | ||
Percentage of Plan Assets | 54.00% | ||
Cash and Short-Term Equivalents [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 8 | ||
Percentage of Plan Assets | 0.40% | ||
Equities [Member] | Domestic [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 5.8 | ||
Percentage of Plan Assets | 0.30% | ||
Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 275.3 | ||
Percentage of Plan Assets | 12.80% | ||
Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 855.6 | ||
Percentage of Plan Assets | 39.60% | ||
Real Estate [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 0.8 | ||
Derivative [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 9.3 | ||
Percentage of Plan Assets | 0.40% | ||
Defined Benefit Plan, Other [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 10.9 | ||
Percentage of Plan Assets | 0.50% | ||
Level 1 [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 391.2 | ||
Level 1 [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 8 | ||
Level 1 [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 5.8 | ||
Level 1 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 272.7 | ||
Level 1 [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 104.7 | ||
Level 2 [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 774.5 | ||
Level 2 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 2.6 | ||
Level 2 [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 750.9 | ||
Level 2 [Member] | Derivative [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 9.3 | ||
Level 2 [Member] | Defined Benefit Plan, Other [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 11.7 | ||
Fair Value Measured at NAV [Member] | Commingled Funds And Pooled Separate Accounts [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 945.3 | ||
Percentage of Plan Assets | 43.80% | ||
Fair Value Measured at NAV [Member] | Private Equity/Limited Partnership [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 48.2 | ||
Percentage of Plan Assets | 2.20% | ||
Canada [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 13.8 | ||
Percentage of Plan Assets | 100.00% | ||
Canada [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 1.7 | ||
Percentage of Plan Assets | 12.30% | ||
Canada [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 3.7 | ||
Percentage of Plan Assets | 26.80% | ||
Canada [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 2.1 | ||
Percentage of Plan Assets | 15.20% | ||
Canada [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 5.5 | ||
Percentage of Plan Assets | 39.90% | ||
Canada [Member] | Real Estate [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 0.8 | ||
Percentage of Plan Assets | 5.80% | ||
Canada [Member] | Level 1 [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 13 | ||
Canada [Member] | Level 1 [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 1.7 | ||
Canada [Member] | Level 1 [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 3.7 | ||
Canada [Member] | Level 1 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 2.1 | ||
Canada [Member] | Level 1 [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 5.5 | ||
Canada [Member] | Level 2 [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 0.8 | ||
Canada [Member] | Level 2 [Member] | Real Estate [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 0.8 | ||
United States [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total fair value of plan investment | 2,145.4 | ||
Fair value of Plan Assets | $ 2,145.3 | ||
Percentage of Plan Assets | 100.00% | ||
United States [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 1,151.9 | ||
Percentage of Plan Assets | 53.60% | ||
United States [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 6.3 | ||
Percentage of Plan Assets | 0.30% | ||
United States [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 2.1 | ||
Percentage of Plan Assets | 0.10% | ||
United States [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 273.2 | ||
Percentage of Plan Assets | 12.70% | ||
United States [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 850.1 | ||
Percentage of Plan Assets | 39.60% | ||
United States [Member] | Derivative [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 9.3 | ||
Percentage of Plan Assets | 0.40% | ||
United States [Member] | Defined Benefit Plan, Other [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 10.9 | ||
Percentage of Plan Assets | 0.50% | ||
United States [Member] | Level 1 [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 378.2 | ||
United States [Member] | Level 1 [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 6.3 | ||
United States [Member] | Level 1 [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 2.1 | ||
United States [Member] | Level 1 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 270.6 | ||
United States [Member] | Level 1 [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 99.2 | ||
United States [Member] | Level 2 [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 773.7 | ||
United States [Member] | Level 2 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 2.6 | ||
United States [Member] | Level 2 [Member] | Fixed Income [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 750.9 | ||
United States [Member] | Level 2 [Member] | Derivative [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 9.3 | ||
United States [Member] | Level 2 [Member] | Defined Benefit Plan, Other [Member] | Fair Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 10.9 | ||
United States [Member] | Fair Value Measured at NAV [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Net payable | (0.1) | ||
United States [Member] | Fair Value Measured at NAV [Member] | Commingled Funds And Pooled Separate Accounts [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 945.3 | ||
Percentage of Plan Assets | 44.20% | ||
United States [Member] | Fair Value Measured at NAV [Member] | Private Equity/Limited Partnership [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 48.2 | ||
Percentage of Plan Assets | 2.20% | ||
Defined Benefit Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 1,367.9 | $ 363.9 | $ 328.4 |
Defined Benefit Plans [Member] | Canada [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 13.8 | 115.2 | 101.5 |
Defined Benefit Plans [Member] | United States [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 1,354.1 | 248.7 | 226.9 |
Defined Benefit Plans [Member] | WGL Holdings [Member] | Money Market Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Target asset mix | 1.00% | ||
Defined Benefit Plans [Member] | WGL Holdings [Member] | United States [Member] | Commingled Funds And Pooled Separate Accounts [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Target asset mix | 89.00% | ||
Defined Benefit Plans [Member] | WGL Holdings [Member] | United States [Member] | Income Producing Properties [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Target asset mix | 10.00% | ||
Post-Retirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 791.2 | 78.9 | 74 |
Post-Retirement Benefits [Member] | Canada [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | 8.1 | 6.8 | |
Post-Retirement Benefits [Member] | United States [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of Plan Assets | $ 791.2 | $ 70.8 | $ 67.2 |
Post-Retirement Benefits [Member] | WGL Holdings [Member] | Corporate Bond Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Target asset mix | 26.00% | ||
Post-Retirement Benefits [Member] | WGL Holdings [Member] | United States [Member] | Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Target asset mix | 20.00% | ||
Post-Retirement Benefits [Member] | WGL Holdings [Member] | United States [Member] | Common Stock, Large Cap [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Target asset mix | 54.00% |
PENSION PLANS AND RETIREE BE_13
PENSION PLANS AND RETIREE BENEFITS (Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations) (Details) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plans [Member] | ||
Significant actuarial assumptions used in measuring net benefit plan costs | ||
Expected long-term rate of return on plan assets | 7.60% | |
Average remaining service life of active employees | 9 years 7 months 6 days | 12 years 8 months 12 days |
Defined Benefit Plans [Member] | Minimum [Member] | ||
Significant actuarial assumptions used in measuring net benefit plan costs | ||
Discount rate | 3.25% | 2.65% |
Expected long-term rate of return on plan assets | 3.20% | 6.18% |
Rate of compensation increase | 2.75% | 2.75% |
Significant actuarial assumptions used in measuring benefit obligations | ||
Discount rate | 3.60% | 2.80% |
Rate of compensation increase | 2.75% | 2.75% |
Defined Benefit Plans [Member] | Maximum [Member] | ||
Significant actuarial assumptions used in measuring net benefit plan costs | ||
Discount rate | 4.30% | 4.20% |
Expected long-term rate of return on plan assets | 7.30% | |
Rate of compensation increase | 4.10% | 4.00% |
Significant actuarial assumptions used in measuring benefit obligations | ||
Discount rate | 4.40% | 3.70% |
Rate of compensation increase | 4.10% | 4.00% |
Post-Retirement Benefits [Member] | ||
Significant actuarial assumptions used in measuring net benefit plan costs | ||
Rate of compensation increase | 4.10% | 3.25% |
Average remaining service life of active employees | 14 years 1 month 6 days | 13 years 6 months |
Significant actuarial assumptions used in measuring benefit obligations | ||
Rate of compensation increase | 4.10% | 3.25% |
Post-Retirement Benefits [Member] | Minimum [Member] | ||
Significant actuarial assumptions used in measuring net benefit plan costs | ||
Discount rate | 3.60% | |
Expected long-term rate of return on plan assets | 3.75% | 3.10% |
Significant actuarial assumptions used in measuring benefit obligations | ||
Discount rate | 3.90% | 3.60% |
Post-Retirement Benefits [Member] | Maximum [Member] | ||
Significant actuarial assumptions used in measuring net benefit plan costs | ||
Discount rate | 4.30% | |
Expected long-term rate of return on plan assets | 7.60% | 7.30% |
Significant actuarial assumptions used in measuring benefit obligations | ||
Discount rate | 4.50% | 3.70% |
PENSION PLANS AND RETIREE BE_14
PENSION PLANS AND RETIREE BENEFITS (Summary of Assumed Health Care Cost Trend Rates) (Details) | 12 Months Ended |
Dec. 31, 2018CAD ($) | |
PENSION PLANS AND RETIREE BENEFITS [Abstract] | |
Increase, Service and interest costs | $ 1,700,000 |
Decrease, Service and interest costs | (1,300,000) |
Increase, Accrued benefit obligations | 19,800,000 |
Decrease, Accrued benefit obligation | $ (16,000,000) |
PENSION PLANS AND RETIREE BE_15
PENSION PLANS AND RETIREE BENEFITS (Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans) (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Defined Benefit Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected employer contributions, 2019 | $ 41.4 |
Expected benefit payments, 2019 | 109.8 |
Expected benefit payments, 2020 | 92.2 |
Expected benefit payments, 2021 | 95.3 |
Expected benefit payments, 2022 | 101 |
Expected benefit payments, 2023 | 99.4 |
Expected benefit payments, 2024 - 2028 | 521.9 |
Post-Retirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected employer contributions, 2019 | 0.1 |
Expected benefit payments, 2019 | 25.3 |
Expected benefit payments, 2020 | 24.6 |
Expected benefit payments, 2021 | 25 |
Expected benefit payments, 2022 | 25.4 |
Expected benefit payments, 2023 | 25.5 |
Expected benefit payments, 2024 - 2028 | $ 130.9 |
COMMITMENTS, CONTINGENCIES AN_3
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Narrative) (Details) $ in Millions, $ in Millions | Apr. 04, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) |
Commitments, Contingencies And Guaranteed [Line Items] | |||
Guarantee obligations | $ 0 | ||
Regulatory Commitments | 140 | ||
Regulatory Commitments Paid | 111 | ||
Loss on Contracts | 40 | ||
Loss Contingency, Damages Sought, Value | $ 100 | ||
Loss Contingency Accrual | $ 0 | ||
Damage Prevention Trainers, Investment [Member] | |||
Commitments, Contingencies And Guaranteed [Line Items] | |||
Regulatory Commitments | $ 70 | ||
Regulatory Commitments Term | 10 years | ||
Leak Mitigation [Member] | |||
Commitments, Contingencies And Guaranteed [Line Items] | |||
Regulatory Commitments | $ 8 |
COMMITMENTS, CONTINGENCIES AN_4
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Summary of Future Payment Commitments) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)item | Dec. 31, 2017 | |
Other Commitments [Line Items] | ||
Operating leases, 2019 | $ 23.9 | |
Operating leases, 2020 | 30.9 | |
Operating leases, 2021 | 29.4 | |
Operating leases, 2022 | 28 | |
Operating leases, 2023 | 25.8 | |
Operating leases, 2024 and beyond | 164.8 | |
Operating leases | 302.8 | |
Commitments, 2019 | 4,804.6 | |
Commitments, 2020 | 4,285.9 | |
Commitments, 2021 | 3,683.4 | |
Commitments, 2022 | 3,426.6 | |
Commitments, 2023 | 3,197.5 | |
Commitments, 2024 and beyond | 35,350.3 | |
Commitments | 54,748.3 | |
Capital Projects [Member] | ||
Other Commitments [Line Items] | ||
Other commitments, 2019 | 119.2 | |
Other commitments, 2020 | ||
Other commitments, 2021 | ||
Other commitments, 2022 | ||
Other commitments, 2023 | ||
Other commitments, 2024 and beyond | ||
Other commitments | 119.2 | |
Environmental [Member] | ||
Other Commitments [Line Items] | ||
Other commitments, 2019 | 6.1 | |
Other commitments, 2020 | 4.7 | |
Other commitments, 2021 | 3 | |
Other commitments, 2022 | 0.5 | |
Other commitments, 2023 | 0.4 | |
Other commitments, 2024 and beyond | 0.5 | |
Other commitments | 15.2 | |
Merger Commitments [Member] | ||
Other Commitments [Line Items] | ||
Other commitments, 2019 | 29.3 | |
Other commitments, 2020 | 30.8 | |
Other commitments, 2021 | 22.8 | |
Other commitments, 2022 | 19.2 | |
Other commitments, 2023 | 19.2 | |
Other commitments, 2024 and beyond | 62.1 | |
Other commitments | 183.4 | |
Natural Gas [Member] | ||
Other Commitments [Line Items] | ||
Purchase obligations, 2019 | 3,157.1 | |
Purchase obligations, 2020 | 2,940.5 | |
Purchase obligations, 2021 | 2,639.3 | |
Purchase obligations, 2022 | 2,527.4 | |
Purchase obligations, 2023 | 2,349.9 | |
Purchase obligations, 2024 and beyond | 30,309.2 | |
Purchase obligations | 43,923.4 | |
Electricity Purchase [Member] | ||
Other Commitments [Line Items] | ||
Purchase obligations, 2019 | 533.1 | |
Purchase obligations, 2020 | 368.6 | |
Purchase obligations, 2021 | 139.2 | |
Purchase obligations, 2022 | 38.6 | |
Purchase obligations, 2023 | 5.7 | |
Purchase obligations, 2024 and beyond | 0.4 | |
Purchase obligations | 1,085.6 | |
Service Agreements [Member] | ||
Other Commitments [Line Items] | ||
Purchase obligations, 2019 | 74.3 | |
Purchase obligations, 2020 | 48.2 | |
Purchase obligations, 2021 | 30.9 | |
Purchase obligations, 2022 | 17.3 | |
Purchase obligations, 2023 | 14.8 | |
Purchase obligations, 2024 and beyond | 168 | |
Purchase obligations | $ 353.5 | |
Service agreement term, (EOH/CT) | item | 124,000 | |
Service agreement term | 25 years | 12 years |
Service agreement payable | $ 190.9 | |
Service agreement payable in five years | $ 59.6 | |
Service agreement payment period | 16 years | |
Contract Fees | $ 60.1 | |
Storage Services [Member] | ||
Other Commitments [Line Items] | ||
Purchase obligations, 2019 | 861.6 | |
Purchase obligations, 2020 | 862.2 | |
Purchase obligations, 2021 | 818.8 | |
Purchase obligations, 2022 | 795.6 | |
Purchase obligations, 2023 | 781.7 | |
Purchase obligations, 2024 and beyond | 4,645.3 | |
Purchase obligations | 8,765.2 | |
Electricity, Renewable Energy Credits [Member] | ||
Other Commitments [Line Items] | ||
Purchase obligations | $ 44.1 |
RELATED PARTY TRANSACTIONS (Sum
RELATED PARTY TRANSACTIONS (Summary of Related Party Amounts Included in Balance Sheets) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Related Party Transaction [Line Items] | ||
Due from related parties, Accounts receivable | $ 60.8 | $ 0.8 |
Due from related parties, Long-term investments and other assets | 45 | 75 |
Due from related parties | 105.8 | 75.8 |
Due to related parties, Accounts payable | 6.3 | 3.2 |
Due to related parties, Risk management liabilities - current | 0.9 | |
Due to related parties | 7.2 | 3.2 |
Petrogas [Member] | AltaGas [Member] | ||
Related Party Transaction [Line Items] | ||
Due from related parties, Long-term investments and other assets | 45 | $ 75 |
Credit facility maximum borrowing capacity | 100 | |
Committed amount | $ 50 | |
Maturity date | Jun. 27, 2021 |
RELATED PARTY TRANSACTIONS (Sch
RELATED PARTY TRANSACTIONS (Schedule of Related Party Transactions) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | ||
Related Party Transaction [Line Items] | |||
Revenue | [1] | $ 68.4 | $ 15 |
Cost of sales | [2] | (4.2) | (6.5) |
Operating and administrative expenses | [3] | 1.3 | |
Other income | [4] | 9.2 | 4.4 |
Unrealized Loss On Foreign Exchange Hedge With ACI [Member] | |||
Related Party Transaction [Line Items] | |||
Revenue | $ 0.2 | ||
[1] | Year ended December 3120182017Revenue (a)$ 68.4 $ 15.0 Cost of sales (b)$ (4.2)$ (6.5)Operating and administrative expenses (c)$ 1.3 $ -Other income (d)$ 9.2 $ 4.4 In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil). | ||
[2] | In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates. | ||
[3] | Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive. | ||
[4] | Interest income from loans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018. |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Schedule of Changes in Operating Assets and Liabilities) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract] | ||
Accounts receivable | $ (526.9) | $ (55.6) |
Inventory | (100.8) | 4.7 |
Other current assets | 12.5 | 7 |
Regulatory assets (current) | (15.8) | (0.2) |
Accounts payable and accrued liabilities | 237.9 | 85.4 |
Customer deposits | (13.3) | (2.8) |
Regulatory liabilities (current) | 69.2 | (4.8) |
Other current liabilities | (5.9) | 13 |
Other operating assets and liabilities | (143.4) | (44.8) |
Changes in operating assets and liabilities | $ (486.5) | $ 1.9 |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION (Schedule of Supplemental Cash Payments) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract] | ||
Interest paid (net of capitalized interest) | $ 288.9 | $ 151.1 |
Income taxes paid | $ 36.9 | $ 36.3 |
SUPPLEMENTAL CASH FLOW INFORM_5
SUPPLEMENTAL CASH FLOW INFORMATION (Reconciliation of Cash and Restricted Cash Balances) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract] | |||
Cash and cash equivalents | $ 101.6 | $ 27.3 | |
Restricted cash holdings from customers - current | 4.1 | 8.9 | |
Restricted cash holdings from customers - non-current | 6.1 | 7.5 | |
Restricted Cash Included In Prepaid Expesnes And Other Current Assets | 27.6 | ||
Restricted Cash Included In Long-Term Investments And Other Assets | 61.7 | ||
Cash, cash equivalents and restricted cash per consolidated statement of cash flow | 201.1 | $ 43.7 | $ 34.1 |
Restricted cash acquired | $ 81 |
SEGMENTED INFORMATION (Narrativ
SEGMENTED INFORMATION (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2018segment | |
SEGMENTED INFORMATION [Abstract] | |
Number of reporting segments | 4 |
SEGMENTED INFORMATION (Reconcil
SEGMENTED INFORMATION (Reconciliation Of Segment Revenue) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues | $ 4,256.7 | $ 2,556.2 |
Operating Segments [Member] | ||
Revenues | 4,369.2 | |
Intersegment Eliminations [Member] | ||
Revenues | (112.5) | |
Utilities [Member] | ||
Revenues | 1,752.6 | |
Utilities [Member] | Operating Segments [Member] | ||
Revenues | 1,765.6 | |
Utilities [Member] | Intersegment Eliminations [Member] | ||
Revenues | (13) | |
Midstream [Member] | ||
Revenues | 1,344.6 | |
Midstream [Member] | Operating Segments [Member] | ||
Revenues | 1,435 | |
Midstream [Member] | Intersegment Eliminations [Member] | ||
Revenues | (90.4) | |
Power [Member] | ||
Revenues | 1,162 | |
Power [Member] | Operating Segments [Member] | ||
Revenues | 1,171 | |
Power [Member] | Intersegment Eliminations [Member] | ||
Revenues | (9) | |
Corporate [Member] | ||
Revenues | (2.5) | |
Corporate [Member] | Operating Segments [Member] | ||
Revenues | (2.4) | |
Corporate [Member] | Intersegment Eliminations [Member] | ||
Revenues | $ (0.1) |
SEGMENTED INFOMRATION (Schedule
SEGMENTED INFOMRATION (Schedule of Geographic Information) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | ||
Revenues | $ 4,256.7 | $ 2,556.2 |
Property, plant and equipment | 10,929.6 | 6,689.8 |
Operating Segments [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 4,179.8 | 2,618.7 |
Canada [Member] | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 2,348.2 | 4,320.5 |
Canada [Member] | Operating Segments [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 1,626.8 | 1,508.8 |
United States [Member] | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 8,581.4 | 2,369.3 |
United States [Member] | Operating Segments [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | $ 2,553 | $ 1,109.9 |
SEGMENTED INFORMATION (Schedule
SEGMENTED INFORMATION (Schedule of Segment Composition) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | ||
Revenues | $ 4,256.7 | $ 2,556.2 |
Cost of sales | (2,455.3) | (1,357.1) |
Operating and administrative | (1,129) | (572.2) |
Accretion expenses | (10.9) | (10.9) |
Depreciation and amortization | (394) | (282.4) |
Provisions on assets | (728.7) | (139.6) |
Income from equity investments (note 13) | 47.9 | 31.4 |
Other income (loss) | 0.9 | 9.6 |
Foreign exchange gains | 4.5 | 1.7 |
Interest expense | (309) | (170.3) |
Income (loss) before income taxes | (716.9) | 66.4 |
Net additions (reductions) to property, plant and equipment | 572.5 | 387.6 |
Net additions (reductions) to intangible assets | 45.7 | 20.3 |
Corporate [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | (2.4) | (58.4) |
Operating and administrative | (50.6) | (97.5) |
Depreciation and amortization | (13.3) | (14) |
Other income (loss) | 2 | 6.3 |
Foreign exchange gains | 4.8 | 1.5 |
Interest expense | (185.6) | (170.3) |
Income (loss) before income taxes | (245.1) | (332.4) |
Net additions (reductions) to property, plant and equipment | 4 | 1.5 |
Net additions (reductions) to intangible assets | 6.7 | 2.2 |
Operating Segments [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 4,179.8 | 2,618.7 |
Operating Segments [Member] | Midstream [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 1,435 | 1,008 |
Cost of sales | (976.4) | (647) |
Operating and administrative | (201.7) | (165) |
Accretion expenses | (4) | (3.9) |
Depreciation and amortization | (84.4) | (68.6) |
Provisions on assets | (153.7) | (6.6) |
Income from equity investments (note 13) | 51.1 | 22 |
Other income (loss) | 0.7 | (0.9) |
Foreign exchange gains | (0.2) | 0.2 |
Interest expense | (10.6) | |
Income (loss) before income taxes | 55.8 | 138.2 |
Net additions (reductions) to property, plant and equipment | 383.4 | 245.3 |
Net additions (reductions) to intangible assets | 4.7 | 2.8 |
Operating Segments [Member] | Power [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 1,171 | 631.7 |
Cost of sales | (743.7) | (242.8) |
Operating and administrative | (159.1) | (93.1) |
Accretion expenses | (6.8) | (6.9) |
Depreciation and amortization | (130.5) | (118) |
Provisions on assets | (381.3) | (133) |
Income from equity investments (note 13) | (10.4) | 6.8 |
Other income (loss) | (5.9) | 0.8 |
Foreign exchange gains | (0.1) | |
Interest expense | (8.9) | |
Income (loss) before income taxes | (275.7) | 45.5 |
Net additions (reductions) to property, plant and equipment | (321.9) | 16.5 |
Net additions (reductions) to intangible assets | 12.5 | 13.2 |
Operating Segments [Member] | Utilities [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | 1,765.6 | 1,126.7 |
Cost of sales | (838.3) | (610.1) |
Operating and administrative | (727.4) | (226.1) |
Accretion expenses | (0.1) | (0.1) |
Depreciation and amortization | (165.8) | (81.8) |
Provisions on assets | (193.7) | |
Income from equity investments (note 13) | 7.2 | 2.6 |
Other income (loss) | 4.5 | 3.9 |
Interest expense | (103.9) | |
Income (loss) before income taxes | (251.9) | 215.1 |
Net additions (reductions) to property, plant and equipment | 507 | 124.3 |
Net additions (reductions) to intangible assets | 21.8 | 2.1 |
Intersegment Eliminations [Member] | ||
Segment Reporting Information [Line Items] | ||
Revenues | (112.5) | (151.8) |
Cost of sales | 103.1 | 142.8 |
Operating and administrative | 9.8 | 9.5 |
Other income (loss) | $ (0.4) | $ (0.5) |
SEGMENTED INFORMATION (Schedu_2
SEGMENTED INFORMATION (Schedule of Goodwilll and Total Assets by Segment) (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Segment Reporting Information [Line Items] | |||
Goodwill | $ 4,068.2 | $ 817.3 | $ 856 |
Segmented assets | 23,487.7 | 10,032.2 | |
Corporate [Member] | |||
Segment Reporting Information [Line Items] | |||
Segmented assets | 282.9 | 282.7 | |
Operating Segments [Member] | Midstream [Member] | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 426.4 | 152.6 | |
Segmented assets | 6,398.8 | 3,096.8 | |
Operating Segments [Member] | Power [Member] | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 191 | ||
Segmented assets | 3,814.7 | 3,192.5 | |
Operating Segments [Member] | Utilities [Member] | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 3,450.8 | 664.7 | |
Segmented assets | $ 12,991.3 | $ 3,460.2 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) $ in Millions | Jan. 31, 2019CAD ($) |
Northwest Hydro Facilities [Member] | Subsequent Event [Member] | |
Subsequent Event [Line Items] | |
Proceeds from sale of facilities | $ 1,370 |
Uncategorized Items - cik000169
Label | Element | Value |
Accounting Standards Update201601 [Member] | Retained Earnings [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ (7,100,000) |