Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018shares | |
Document and Entity Information [Abstract] | |
Entity Registrant Name | Fortis Inc. |
Entity Central Index Key | 1,666,175 |
Current Fiscal Year End Date | --12-31 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2018 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 428,460,460 |
Entity Current Reporting Status | Yes |
Entity Emerging Growth Company | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Current assets | |||
Cash and cash equivalents | $ 332 | $ 327 | |
Accounts receivable and other current assets (Note 7) | 1,357 | 1,131 | |
Prepaid expenses | 84 | 79 | |
Inventories (Note 8) | 398 | 367 | |
Regulatory assets (Note 9) | 324 | 303 | |
Assets held for sale (Note 10) | 766 | 0 | |
Total current assets | 3,261 | 2,207 | |
Other assets (Note 11) | 552 | 480 | |
Regulatory assets (Note 9) | 2,854 | 2,742 | |
Property, plant and equipment, net (Note 12) | 32,654 | 29,668 | |
Intangible assets, net (Note 13) | 1,200 | 1,081 | |
Goodwill (Note 14) | 12,530 | 11,644 | |
Total assets | 53,051 | 47,822 | |
Current liabilities | |||
Short-term borrowings (Note 16) | 60 | 209 | |
Accounts payable and other current liabilities (Note 15) | 2,289 | 2,053 | |
Regulatory liabilities (Note 9) | 656 | 490 | |
Current installments of long-term debt (Note 16) | 926 | 705 | |
Current installments of capital lease and finance obligations (Note 17) | 252 | 47 | |
Liabilities associated with assets held for sale (Note 10) | 69 | 0 | |
Total current liabilities | 4,252 | 3,504 | |
Other liabilities (Note 18) | 1,138 | 1,210 | |
Regulatory liabilities (Note 9) | 2,970 | 2,956 | |
Deferred income taxes (Note 24) | 2,686 | 2,298 | |
Long-term debt (Note 16) | 23,159 | 20,691 | |
Capital lease and finance obligations (Note 17) | 390 | 414 | |
Total liabilities | 34,595 | 31,073 | |
Commitments and contingencies (Note 30) | |||
Equity | |||
Common shares | [1] | 11,889 | 11,582 |
Preference shares (Note 20) | 1,623 | 1,623 | |
Additional paid-in capital | 11 | 10 | |
Accumulated other comprehensive income (Note 21) | 928 | 61 | |
Retained earnings | 2,082 | 1,727 | |
Shareholders' equity | 16,533 | 15,003 | |
Non-controlling interests | 1,923 | 1,746 | |
Total equity | 18,456 | 16,749 | |
Total liabilities and equity | $ 53,051 | $ 47,822 | |
[1] | No par value. Unlimited authorized shares; 428.5 million and 421.1 million issued and outstanding as at December 31, 2018 and 2017, respectively |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - shares shares in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Issued (shares) | 428.5 | 421.1 |
Outstanding (shares) | 428.5 | 421.1 |
Consolidated Statements of Earn
Consolidated Statements of Earnings - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement [Abstract] | ||
Revenue (Note 6) | $ 8,390 | $ 8,301 |
Expenses | ||
Energy supply costs | 2,495 | 2,361 |
Operating expenses | 2,287 | 2,250 |
Depreciation and amortization | 1,243 | 1,179 |
Total expenses | 6,025 | 5,790 |
Operating income | 2,365 | 2,511 |
Other income, net (Note 23) | 60 | 116 |
Finance charges | 974 | 914 |
Earnings before income tax expense | 1,451 | 1,713 |
Income tax expense (Note 24) | 165 | 588 |
Net earnings | 1,286 | 1,125 |
Net earnings attributable to: | ||
Non-controlling interests | 120 | 97 |
Preference equity shareholders | 66 | 65 |
Common equity shareholders | 1,100 | 963 |
Net earnings | $ 1,286 | $ 1,125 |
Earnings per common share (Note 19) | ||
Basic (CAD per share) | $ 2.59 | $ 2.32 |
Diluted (CAD per share) | $ 2.59 | $ 2.31 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Comprehensive Income [Abstract] | ||
Net earnings | $ 1,286 | $ 1,125 |
Other comprehensive income (loss) | ||
Unrealized foreign currency translation gains (losses), net of hedging activities and income tax recovery (expense) of $11 million and $(2) million, respectively | 985 | (781) |
Other, net of income tax expense of $2 million and nil, respectively | 6 | (2) |
Other comprehensive income (loss) | 991 | (783) |
Comprehensive income | 2,277 | 342 |
Comprehensive income (loss) attributable to: | ||
Non-controlling interests | 244 | (2) |
Preference equity shareholders | 66 | 65 |
Common equity shareholders | 1,967 | 279 |
Comprehensive income | $ 2,277 | $ 342 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Comprehensive Income [Abstract] | ||
Unrealized foreign currency translation, tax recovery (expense) | $ 11 | $ (2) |
Other, tax | $ 2 | $ 0 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Operating activities | ||
Net earnings | $ 1,286 | $ 1,125 |
Adjustments to reconcile net earnings to net cash provided by operating activities: | ||
Depreciation - property, plant and equipment | 1,107 | 1,055 |
Amortization - intangible assets | 106 | 97 |
Amortization - other | 30 | 27 |
Deferred income tax expense (Note 24) | 136 | 544 |
Equity component, allowance for funds used during construction (Note 23) | (64) | (74) |
Other | 92 | 11 |
Change in long-term regulatory assets and liabilities | 13 | 68 |
Change in working capital (Note 27) | (102) | (97) |
Cash from operating activities | 2,604 | 2,756 |
Investing activities | ||
Capital expenditures - property, plant and equipment | (3,032) | (2,813) |
Capital expenditures - intangible assets | (186) | (211) |
Contributions in aid of construction | 106 | 102 |
Other | (140) | (103) |
Cash used in investing activities | (3,252) | (3,025) |
Financing activities | ||
Proceeds from long-term debt, net of issuance costs (Note 16) | 1,566 | 2,538 |
Repayments of long-term debt and capital lease and finance obligations | (563) | (952) |
Borrowings under committed credit facilities (Note 31) | 5,666 | 6,461 |
Repayments under committed credit facilities (Note 31) | (5,523) | (7,480) |
Net change in short-term borrowings (Note 31) | 38 | (192) |
Issue of common shares, net of costs, and dividends reinvested | 34 | 561 |
Dividends | ||
Common shares, net of dividends reinvested | (459) | (419) |
Preference shares | (66) | (65) |
Subsidiary dividends paid to non-controlling interests | (85) | (109) |
Other | 36 | (4) |
Cash from financing activities | 644 | 339 |
Effect of exchange rate changes on cash and cash equivalents | 24 | (12) |
Change in cash and cash equivalents | 20 | 58 |
Less: Cash associated with assets held for sale (Note 10) | (15) | 0 |
Cash and cash equivalents, beginning of year | 327 | 269 |
Cash and cash equivalents, end of year | $ 332 | $ 327 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) shares in Millions, $ in Millions | Total | Common Shares | Preference Shares (Note 20) | Additional Paid-In Capital | Accumulated Other Comprehensive Income (Loss) (Note 21) | Retained Earnings | Non-Controlling Interests |
Beginning balance at Dec. 31, 2016 | $ 16,450 | $ 10,762 | $ 1,623 | $ 12 | $ 745 | $ 1,455 | $ 1,853 |
Beginning balance (shares) at Dec. 31, 2016 | 401.5 | ||||||
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,125 | 1,028 | 97 | ||||
Other comprehensive income (loss) | (783) | (684) | (99) | ||||
Common shares issued | 815 | $ 820 | (5) | ||||
Common shares issued (shares) | 19.6 | ||||||
Subsidiary dividends paid to non-controlling interests | (109) | (109) | |||||
Dividends declared on common shares | (691) | (691) | |||||
Dividends declared on preference shares | (65) | (65) | |||||
Other | 7 | 3 | 4 | ||||
Ending balance at Dec. 31, 2017 | 16,749 | $ 11,582 | 1,623 | 10 | 61 | 1,727 | 1,746 |
Ending balance (shares) at Dec. 31, 2017 | 421.1 | ||||||
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,286 | 1,166 | 120 | ||||
Other comprehensive income (loss) | 991 | 867 | 124 | ||||
Common shares issued | 306 | $ 307 | (1) | ||||
Common shares issued (shares) | 7.4 | ||||||
Subsidiary dividends paid to non-controlling interests | (85) | (85) | |||||
Dividends declared on common shares | (745) | (745) | |||||
Dividends declared on preference shares | (66) | (66) | |||||
Other | 20 | 2 | 18 | ||||
Ending balance at Dec. 31, 2018 | $ 18,456 | $ 11,889 | $ 1,623 | $ 11 | $ 928 | $ 2,082 | $ 1,923 |
Ending balance (shares) at Dec. 31, 2018 | 428.5 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Stockholders' Equity [Abstract] | ||
Dividends declared (CAD per share) | $ 1.75 | $ 1.65 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | DESCRIPTION OF BUSINESS Fortis Inc. ("Fortis" or the "Corporation") is principally a North American electric and gas utility holding company. Entities within the reporting segments that follow operate with substantial autonomy. Regulated Utilities ITC: Primarily comprised of ITC Holdings Corp., ITC Investment Holdings Inc. and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company ("ITCTransmission"), Michigan Electric Transmission Company, LLC ("METC"), ITC Midwest LLC ("ITC Midwest"), and ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest. ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. UNS Energy: Comprised of UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"). UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and distribute electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County and parts of Cochise County, as well as in Santa Cruz and Mohave counties. TEP also sells wholesale electricity to other entities in the western United States. Together they own generation capacity of 3,377 megawatts ("MW"), including 57 MW of solar capacity. Several generating assets in which they have an interest are jointly owned. UNS Gas is a regulated gas distribution utility serving retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties. Central Hudson: Primarily comprised of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric generating capacity totalling 64 MW. FortisBC Energy: Primarily comprised of FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing transmission and distribution services in over 135 communities. FortisBC Energy obtains natural gas supplies primarily from northeastern British Columbia and Alberta on behalf of most customers. FortisAlberta: FortisAlberta Inc. is a regulated electricity distribution utility operating in a substantial portion of southern and central Alberta . It is not involved in the direct sale of electricity. FortisBC Electric: Primarily comprised of FortisBC Inc., an integrated regulated electric utility operating in the southern interior of British Columbia . It owns four hydroelectric generating facilities with a combined capacity of 225 MW. It also provides operating, maintenance and management services relating to four hydroelectric generating facilities in British Columbia that are owned by third parties and to the 335 -MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in which Fortis indirectly holds a 51% controlling interest (Notes 10 and 29). Other Electric: Comprised of utilities in eastern Canada and the Caribbean, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company, Limited ("Maritime Electric"); FortisOntario Inc. ("FortisOntario"); a 49% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Partnership") (Note 11 ) ; an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("BEL") (Note 11 ). In January 2019 Fortis reduced its equity investment in Wataynikaneyap Partnership from 49% to 39% to facilitate the inclusion of two additional First Nations communities into the partnership. Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador with a generating capacity of 139 MW, of which 97 MW is hydroelectric. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI") with on-Island generating capacity of 145 MW. FortisOntario is comprised of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. Wataynikaneyap Partnership is a partnership between 24 First Nations communities and Fortis with a mandate of connecting remote First Nations communities to the electricity grid in Ontario through the development of new transmission lines. Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating capacity of 161 MW. FortisTCI is comprised of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a diesel-powered generating capacity of 91 MW. BEL is an integrated electric utility and the principal distributor of electricity in Belize. Non-Regulated Energy Infrastructure: Primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek"). Generation assets in British Columbia include the Corporation's interest in the Waneta Expansion (Note 10), whose output is sold to British Columbia Hydro and Power Authority ("BC Hydro") and FortisBC Electric under 40 -year power purchase agreements ("PPAs"). Generation assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW, conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL"). The output is sold to BEL under 50 -year PPAs. Fortis indirectly owns 93.8% of Aitken Creek, with the remainder owned by BP Canada Energy Company . Aitken Creek is the only underground natural gas storage facility in British Columbia and has a working gas capacity of 77 billion cubic feet. Corporate and Other: Captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments, including net corporate expenses of Fortis and the non-regulated holding company FortisBC Holdings Inc. ("FHI"). |
Regulation
Regulation | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Regulation | REGULATION General The earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation, with some using performance-based rate setting ("PBR") mechanisms. Under COS regulation the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of estimated costs of providing service, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability to recover prudently incurred costs of providing service and earn the regulator‑approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") may depend on achieving the forecasts established in the rate-setting process. Usage of a historical test year may cause regulatory lag between when costs are incurred and when they are reflected in customer rates. When PBR mechanisms are utilized in determining customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements for a set term. PBR mechanisms should allow a utility a reasonable opportunity to recover prudently incurred costs and earn its allowed ROE or ROA. The Corporation's regulated utilities, where applicable, are permitted by their respective regulators to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 9) . ITC ITC is regulated by the Federal Energy Regulatory Commission ("FERC") under the Federal Power Act (United States). Rates are set annually, using FERC-approved cost-based formula rate templates, and remain in effect for one year , which provides timely cost recovery. An annual true-up mechanism compares actual revenue requirements to billed revenues, and any variances are accrued and reflected in future rates within a two -year period. The formula rates do not require annual FERC approvals, although inputs remain subject to legal challenge by customers with FERC. ITC's rates reflect an allowed ROE ranging from 11.07% to 12.16% on a capital structure of 60% common equity for 2018 (ROE range of 11.32% to 12.16% and 60% common equity for 2017 ). Incentive Adder Complaint In April 2018 a third-party complaint was filed with FERC challenging the independence incentive adders that are included in transmission rates charged by transmission owners operating in the Midcontinent Independent System Operator ("MISO") region, which includes ITCTransmission, METC and ITC Midwest (collectively "ITC's MISO Subsidiaries"). The adder allowed up to 0.50% or 1.00% to be added to the authorized ROE, subject to any ROE cap established by FERC. In October 2018 FERC issued an order reducing the adders to 0.25% , effective April 20, 2018. This equates to a 0.25% decrease in ROE, down from the approximate 0.50% that ITC was earning in rates previously approved by FERC. ITC's MISO Subsidiaries sought rehearing of this order and began reflecting the 0.25% adder in transmission rates in November 2018. Refunds began in the fourth quarter of 2018 and were completed in the first quarter of 2019. The order is not expected to have a material impact on the Corporation's earnings or cash flows. ROE Complaints Two third-party complaints requested that the base ROE for MISO transmission owners, including ITC's MISO Subsidiaries, be found to no longer be just or reasonable. The complaints cover two consecutive 15 -month periods from November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint"). FERC orders on the complaints will also set the ROE that will be effective prospectively from the order dates. In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10.32% , down from 12.38% , with a maximum of 11.35% . The resultant rates apply prospectively from September 2016 until an approved ROE is established for the Second Refund Period. The MISO transmission owners sought rehearing of this order. The total refund for the Initial Complaint as a result of the September 2016 FERC order was $158 million (US $118 million ), including interest, and was paid in 2017 (Note 9 ). In June 2016 the presiding Administrative Law Judge ("ALJ") issued an initial decision on the Second Complaint, recommending a base ROE of 9.70% , with a maximum of 10.68% . The initial decision of the ALJ is a non-binding recommendation to FERC, and FERC has yet to issue its order on the Second Complaint. In September 2017 certain MISO transmission owners filed a motion for FERC to dismiss the Second Complaint. Pending an order from FERC, an estimated regulatory liability of $206 million (US $151 million ) has been recognized (December 31, 2017 - $182 million (US $145 million )) (Note 9 ). There is uncertainty regarding the final outcome of the Initial and Second Complaints due in part to a November 2018 FERC order proposing a new methodology for determining a just and reasonable base ROE. If finalized, this proposed methodology will be used to address ITC's outstanding ROE complaints. Briefs are due to be filed in the first half of 2019 on the proposed adoption of the new methodology. UNS Energy UNS Energy is regulated by the Arizona Corporation Commission ("ACC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). UNS Energy uses a historical test year to establish retail electric and gas rates. Effective February 27, 2017, TEP's rates reflect an allowed ROE of 9.75% on a capital structure of approximately 50% common equity, effective from July 1, 2013, prior to which its allowed ROE was 10.0% on a capital structure of 43.5% common equity. Effective August 1, 2016, UNS Electric's rates reflect an allowed ROE of 9.5% on a capital structure of 52.8% common equity. Effective May 1, 2012, UNS Gas' rates reflect an allowed ROE of 9.75% and a capital structure of 50.8% common equity. Central Hudson Central Hudson is regulated by the New York State Public Service Commission ("PSC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). Central Hudson uses a future test year to establish rates. Effective July 1, 2018, pursuant to a three -year settlement agreement arising from a 2017 general rate application, Central Hudson's rates reflect an allowed ROE of 8.8% on a capital structure of 48% , 49% and 50% common equity in rate years one, two and three, respectively. Prior thereto, effective from July 1, 2015, Central Hudson's allowed ROE was 9.0% on a capital structure of 48% common equity. Central Hudson is also subject to an earnings sharing mechanism whereby the Company and its customers share equally earnings between 50 and 100 basis points above the allowed ROE. Earnings beyond this are primarily returned to customers. FortisBC Energy and FortisBC Electric FortisBC Energy and FortisBC Electric are regulated by the British Columbia Utilities Commission ("BCUC") pursuant to the Utilities Commission Act (British Columbia), and are subject to multi-year PBR plans for 2014 through 2019 whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the previous year's rates to establish new rates for the remainder of the multi-year period. The PBR plans incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FortisBC Energy and 1.03% for FortisBC Electric each year. The approved PBR plans also include a 50 /50 sharing of variances from the formula‑driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FortisBC Energy and FortisBC Electric maintain specified service levels. FortisBC Energy is the benchmark utility in British Columbia, as designated by the BCUC, and effective January 1, 2016, its rates reflect an allowed ROE of 8.75% and a capital structure of 38.5% common equity. Effective January 1, 2016, FortisBC Electric's rates reflect an allowed ROE of 9.15% and a capital structure of 40% common equity. FortisAlberta FortisAlberta is regulated by the Alberta Utilities Commission pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Hydro and Electric Energy Act (Alberta) and the Alberta Utilities Commission Act (Alberta). FortisAlberta is subject to multi-year PBR plans for 2013-2017 and 2018-2022 whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the previous year's rates to establish new rates for the remainder of the multi-year period. The PBR plans include mechanisms for the recovery or settlement of items determined to flow through directly to customers ("Y factor") and the recovery of costs related to capital expenditures that are not being recovered through the formula ("capital tracker" or "K-bar"). It also includes a Z factor, a PBR re-opener, and an efficiency carry-over mechanism. The Z factor permits an application for recovery of costs, subject to certain thresholds, related to significant unforeseen events. The PBR re-opener permits, subject to certain thresholds, an application to re-open and review the PBR plan to address specific problems with its design or operation. The efficiency carry-over mechanism provides an efficiency incentive by permitting the Company to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of that term. Pursuant to generic cost of capital proceedings completed in 2018, FortisAlberta's rates reflect an allowed ROE of 8.5% on a capital structure of 37% common equity for 2018-2020, unchanged from 2017. Other Electric Newfoundland Power is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities under the Public Utilities Act (Newfoundland and Labrador) and uses a future test year to establish rates. Effective 2016 to 2018, Newfoundland Power's rates reflect an allowed ROE of 8.5% on a capital structure of 45% common equity. Maritime Electric is regulated by the Island Regulatory and Appeals Commission under the provisions of the Electric Power Act (PEI), the Renewable Energy Act (PEI) and the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), and uses a future test year to establish rates. Effective March 1, 2016 for a three -year period, Maritime Electric's rates reflect an allowed ROE of 9.35% on a capital structure of 40% common equity. FortisOntario's three electric utilities are regulated by the Ontario Energy Board under the Electricity Act (Ontario) and the Ontario Energy Board Act (Ontario). Two of FortisOntario's utilities use a future test year to establish rates under five -year PBR plans whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula using inflationary factors less an efficiency target is applied annually to the previous year's rates to establish new rates for the remainder of the five -year period. The allowed ROEs ranged from 8.78% to 9.30% for both 2018 and 2017, on a capital structure of 40% common equity. FortisOntario's remaining utility is subject to a 35 -year franchise agreement, expiring in 2033, whereby rates are based on a price cap with commodity cost flow through and with the base revenue requirement adjusted annually for inflation, load growth and customer growth. Caribbean Utilities operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial period of 20 years, expiring in April 2028, with a provision for automatic renewal. Its non-exclusive generation licence is for a term of 25 years, expiring in November 2039. It is regulated under a rate‑cap adjustment mechanism based on published consumer price indices. The licences detail the role of the Cayman Islands Utility Regulation and Competition Office, which oversees all licences, establishes and enforces licence standards, reviews the rate-cap adjustment mechanism, and annually approves capital expenditures. Its allowed ROA for 2018 was in the range of 7.00% to 9.00% (range of 6.75% to 8.75% for 2017 ). FortisTCI operates under two 50 -year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037. Rates reflect a historical test year and a targeted allowed ROA of between 15.0% and 17.5% (the "Allowable Operating Profit"). The Allowable Operating Profit is based on a calculated rate base, including interest on the cumulative amount by which actual operating profits fall short of the Allowable Operating Profit (the "Cumulative Shortfall"). The calculated Allowable Operating Profit and Cumulative Shortfall are submitted to the Government annually. The recovery of the Cumulative Shortfall is dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been significantly lower than those allowed as a result of the inability, due to economic and political factors, to increase rates to support significant capital investment in recent years. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated. These consolidated financial statements include the accounts of the Corporation and its subsidiaries and controlled variable interest entity. They reflect the equity method of accounting for entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated entities. Intercompany transactions have been eliminated, except for transactions between non-regulated and regulated entities in accordance with US GAAP for rate-regulated entities. Cash and Cash Equivalents Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit. Allowance for Doubtful Accounts Fortis and each subsidiary, other than ITC, maintains an allowance for doubtful accounts that is estimated based on a variety of factors, including receivables aging, historical experience, specific events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible accounts based upon their specific identification. Accounts receivable are written off in the period in which they are deemed uncollectible. Inventories Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable value. Regulatory Assets and Liabilities Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or 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 will be, or are expected to be, refunded to customers through the rate-setting process. Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory approval. Investments Investments accounted for using the equity method are reviewed annually for potential impairment in value. Impairments are recognized when identified. Property, Plant and Equipment Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE. Depreciation rates of the Corporation's regulated utilities include a provision for estimated future asset removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability ( Note 9 ) against which actual asset removal costs are netted when incurred . Most of the Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon derecognition, any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain or loss is recognized as it is expected that such amounts will be reflected in future depreciation expense when they are refunded or collected in customer rates. Through methodologies established by their respective regulators, most of the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure program; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC totalling $31 million ( 2017 - $38 million ) is reported as a reduction of finance charges and the equity component is reported as other income (Note 23) . Both components are charged to earnings through depreciation expense over the estimated service lives of the applicable PPE. At FortisAlberta the cost of PPE includes required contributions to the Alberta Electric System Operator ("AESO") toward funding the construction of transmission facilities. Excluding UNS Energy, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulator, UNS Energy recognizes such items as inventory until used and reclassifies them to PPE once put into service. Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are capitalized. PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are approved by the respective regulators. Depreciation rates for 2018 ranged from 0.9% to 34.6% ( 2017 - 0.9% to 34.6% ). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.5% for 2018 ( 2017 – 2.6% ). The service life ranges and weighted average remaining service life of the Corporation's PPE as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 33 Gas 14-95 35 14-95 34 Transmission Electric 20-90 42 20-80 41 Gas 5-85 41 5-80 34 Generation 1-85 24 5-85 28 Other 3-70 15 3-70 14 Leases Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the present value of the minimum lease payments. Capital leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting purposes, in which case the timing of the expense recognition will conform to the regulator's requirements. Operating lease payments are recognized as an expense on a straight-line basis over the lease term. Intangible Assets Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite. Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether the indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively. Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 50.0% for 2018 ( 2017 – 1.0% to 50.0% ). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-90 57 36-80 57 Other 10-100 13 10-100 10 Most of the Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use. Upon derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization. No gain or loss is recognized as it is expected that such amounts will be reflected in future amortization costs when they are refunded or collected in customer rates. Impairment of Long-Lived Assets The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the carrying value may not exceed the total undiscounted cash flows expected to be generated by the asset. If that is determined to be the case, the asset is written down to estimated fair value and an impairment loss is recognized. Goodwill Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions. Impairment testing is performed if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. If that is determined to be the case, goodwill is written down to estimated fair value and an impairment loss is recognized. Otherwise, Fortis performs an annual assessment for each of the 11 reporting units having goodwill. The primary method for estimating the fair value of reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value method. The income approach uses underlying estimates and assumptions with varying degrees of uncertainty, including the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation method, the market approach, as well as a reconciliation of the total estimated fair value of all reporting units to the Corporation's market capitalization, are also performed and compared to the results of the income approach. Deferred Financing Costs Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt. Employee Future Benefits Fortis and its subsidiaries each maintains one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post-employment benefit ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The costs of defined contribution pension plans are expensed as incurred. For defined benefit pension plans and OPEB plans, the projected or accumulated benefit obligation and net benefit costs are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and, for OPEB plans, expected health care costs. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension or OPEB payments. Defined benefit pension plan and OPEB plan assets are recognized at fair value. For the purpose of determining defined benefit pension cost, FortisBC Energy and Newfoundland Power use the market-related value whereby investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years . The excess of any cumulative net actuarial gain or loss over 10% of the greater of: (i) the projected or accumulated benefit obligation; and (ii) the fair value or market-related value, as applicable, of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees. The net funded or unfunded status of defined benefit pension and OPEB plans, measured as the difference between the fair value of the plan assets and the projected or accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheets. For most of the Corporation's regulated utilities, any difference between defined benefit pension or OPEB plan costs ordinarily recognized under US GAAP and those recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in future rates ( Note 9 ). For most of the Corporation's regulated utilities, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment ( Note 9 ). Stock-Based Compensation Compensation expense related to stock options is measured at the grant date using the Black-Scholes fair value option-pricing model and each grant is amortized to compensation expense as a single award evenly over the four -year vesting period, with the offsetting entry to additional paid-in capital. Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock. Fortis recognizes liabilities associated with its Directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans, all representing cash-settled awards, at fair value at each reporting date until settlement. The fair value of these liabilities is based on the five -day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP as at December 31, 2018 was $45.14 ( December 31, 2017 - $46.01 ). The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with the defined metrics of each grant and management's best estimate. Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the lesser of three years or the period to retirement eligibility and for the DSU Plan is at the time of grant. Forfeitures are accounted for as they occur. Foreign Currency Translation Assets and liabilities of the Corporation's foreign operations, all of which have a US dollar functional currency, are translated at the exchange rate in effect at the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income. The exchange rate as at December 31, 2018 was US$1.00=CAD$ 1.36 ( December 31, 2017 – US$1.00=CAD$ 1.25 ). Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CAD$ 1.30 for 2018 ( 2017 - US$1.00=CAD$ 1.30 ). Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Translation gains and losses are recognized in earnings. Translation gains and losses on foreign currency-denominated debt that is designated as an effective hedge of foreign net investments are recognized in other comprehensive income. Derivatives and Hedging Derivatives Not Designated as Hedges Derivatives not designated as hedges are used by: (i) Fortis, to manage cash flow risk associated with forecast US dollar cash inflows and forecast future cash settlements of DSU and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions. These derivatives are measured at fair value with changes thereto recognized in earnings. Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the respective regulators. These derivatives are measured at fair value with changes thereto recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 9) . Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in earnings as energy supply costs. Derivatives Designated as Hedges The Corporation, ITC and UNS Energy use cash flow hedges to manage interest rate risk. Unrealized gains and losses are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings. Any hedge ineffectiveness is immediately recognized in earnings. The Corporation's earnings from, and net investments in, foreign subsidiaries and equity-accounted investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through US dollar-denominated debt at the corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated other comprehensive income. Presentation of Derivatives The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivatives are presented in operating activities in the consolidated statements of cash flows. Income Taxes The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year. Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes that are more likely than not to be realized. They are measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation allowances are recognized when it is more likely than not that all, or a portion of, a deferred income tax asset will not be realized. Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta reflect current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and, for certain regulatory balances, deferred income tax. Caribbean Utilities, FortisTCI and, for the 50 -year term of its power purchase agreements, BECOL are not subject to income tax. Differences between the income tax expense or recovery recognized under US GAAP and that reflected in current customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities ( Note 9 ). At FortisAlberta the capital cost allowance pool for certain PPE for rate-setting purposes is different from that prescribed for Canadian tax filing purposes. In a future reporting period yet to be determined, the difference may result in reported income tax expense exceeding that reflected in customer rates. Fortis does not recognize deferred income taxes on temporary differences related to investments in foreign subsidiaries where it intends to indefinitely reinvest earnings. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $2.3 billion as at December 31, 2018 ( December 31, 2017 - $561 million ). If such earnings are repatriated, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is impractical. Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement. Income tax interest and penalties are recognized as income tax expense when incurred. Asset Retirement Obligations The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, right-of-ways and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized. Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 18) if a reasonable estimate of fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated over the useful life of the asset. Actual settlement costs are recognized as a reduction in the accrued liability. Contingencies Fortis and its subsidiaries are involved in certain legal and environmental matters that arise in the normal course of business. Management makes judgments regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss, or range of loss, is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a regulatory asset is also recognized. Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required. However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over long time periods. Actual outcomes may differ materially from the amounts recognized. New Accounting Policies Revenue Recognition Effective January 1, 2018, Fortis adopted Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , which clarifies the principles for recognizing revenue and requires additional disclosures ( Note 6 ). Fortis adopted this standard using the modified retrospective approach, under which comparative periods are not restated and the cumulative impact is recognized at the date of adoption, supplemented by additional disclosures. Upon adoption, there were no adjustments to the opening balance of retained earnings. Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is allocated to unsatisfied performance obligations. Revenue is generally measured in kilowatt hours, gigajoules or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load. FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the AESO. This includes the collection of transmission revenue from its customers, which occurs through the transmission component of its regulator-approved rates. FortisAlberta reports transmission revenue and expenses on a net basis. Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that has not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known. Generation revenue from non-regulated operations is recognized on delivery at contracted fixed or market rates. Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration, including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is certain . Revenue excludes sales and municipal taxes collected from customers. Prior to the adoption of ASC 606, Central Hudson recognized sales tax and FortisAlberta recognized municipal tax on a gross basis in both revenue and expense. The exclusion of these taxes from revenue resulted in a decrease in revenue of $ 49 million for 2018 compared to 2017 . The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal payment plans as the period between the transfer of energy to customers and the customers' payment will be less than one year. Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations ( Note 5 ). This represents the level of disaggregation used by the Corporation's President and Chief Executive Officer ("CEO") to allocate resources and evaluate performance. Financial Instruments Effective January 1, 2018, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities . Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the equity method to be measured at fair value through earnings; however, entities may elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and liabilities to be presented separately in the financial statement notes, grouped by measurement category and form. Adoption did not impact these consolidated financial statements. Pension and Post-Retirement Benefit Costs Effective January 1, 2018, the Corporation adopted ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost , which requires current service costs to be grouped in the statement of earnings with other employee compensation costs arising from services rendered. The remaining components of net periodic benefit costs must be presented separately and outside of operating income. Additionally, only the service cost component can be capitalized. On adoption, the Corporation applied the presentation guidance retrospectively and the capitalization guidance prospectively. This resulted in a retrospective $11 million reclassification from Operating Expenses to Other Income, Net in the consolidated financial statements. Use of Accounting Estimates The preparation of these consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments, including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities, revenues, expenses, gains and losses. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments being recognized in the period they become known. Actual results may differ significantly from these estimates. |
Future Accounting Pronouncement
Future Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Changes and Error Corrections [Abstract] | |
Future Accounting Pronouncements | FUTURE ACCOUNTING PRONOUNCEMENTS Leases ASU No. 2016-02, Leases ("ASC 842"), issued in February 2016, is effective for Fortis January 1, 2019 and is to be applied using a modified retrospective approach or an optional transition method with implementation options, referred to as practical expedients. Principally, it requires balance sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating leases, along with additional disclosures. Fortis has selected the optional transition method, which allows entities to continue to apply the current lease guidance in the comparative periods presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance. Fortis elected a package of practical expedients that allowed it to not reassess the lease classification of existing leases or whether existing contracts, including land easements, are or contain a lease. Finally, Fortis utilized the hindsight practical expedient to determine the lease term. Upon adoption, Fortis will recognize right-of-use assets and corresponding lease liabilities of approximately $50 million for operating leases primarily related to office facilities and utility property. Operating leases related to vehicles and office equipment were identified and quantified as immaterial. Fortis has not identified an adjustment to opening retained earnings, and there will be no impact on earnings or cash flows. Fortis implemented changes to processes and control activities related to monitoring the adoption of ASC 842 and made changes to accounting policies associated with accounting for lease assets and liabilities, and related income and expense, as of January 1, 2019. Financial Instruments ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments , issued in June 2016, is effective for Fortis January 1, 2020 and is to be applied on a modified retrospective basis. Principally, it requires entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to estimate credit losses. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures. Hedging ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities , issued in August 2017, is effective for Fortis January 1, 2019. Principally, it better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. For cash flow and net investment hedges that existed at the date of adoption, the amendments were applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to opening retained earnings. Amended presentation and disclosure guidance was applied prospectively. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures. Fair Value Measurement Disclosures ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, issued in August 2018, is effective for Fortis January 1, 2020 and is to be primarily applied on a retrospective basis, with certain disclosures requiring prospective application. Principally, it improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements. In addition, the amendment removes (a) the amount of, and reasons for, transfers between level 2 and level 3 of the fair value hierarchy, (b) the policy for timing of transfers between levels, and (c) the valuation processes for level 3 fair value measurements. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosures. Pensions and Other Post-Retirement Plan Disclosures ASU No. 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans , issued in August 2018, is effective for Fortis January 1, 2021 and is to be applied on a retrospective basis for all periods presented. Principally, it modifies the disclosure requirements for employers with defined pension or other post-retirement plans and clarifies disclosure requirements. In addition, the amendments remove (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period, (b) the amount and timing of plan assets expected to be returned to the employer, and (c) the effects of a one-percentage-point change on the assumed health care costs and the change in rates on service cost, interest cost and the benefit obligation for post-retirement health care benefits. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosure. |
Segmented Information
Segmented Information | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Segmented Information | SEGMENTED INFORMATION General Fortis segments its business based on regulatory status and service territory, as well as the information used by its President and CEO in deciding how to allocate resources. The performance of each segment is primarily based on net earnings attributable to common equity shareholders. Effective January 1, 2018, the former Eastern Canadian and Caribbean segments were aggregated as Other Electric as they individually do not meet the quantitative threshold for separate reporting. Related-party and inter-company transactions Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions in 2018 or 2017 . Inter-company balances, transactions and profit are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. Inter-company transactions are summarized below. (in millions) 2018 2017 Sale of capacity from Waneta Expansion to FortisBC Electric $ 47 $ 46 Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy 25 24 As at December 31, 2018 , accounts receivable included approximately $16 million due from BEL ( December 31, 2017 - $20 million ). The Corporation periodically provides short-term financing to subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements. There were no material inter-segment loans outstanding as at December 31, 2018 and 2017 . REGULATED NON-REGULATED Year Ended Energy Inter- December 31, 2018 UNS Central FortisBC Fortis FortisBC Other Sub Infra- Corporate segment (in millions) ITC Energy Hudson Energy Alberta Electric Electric total structure and Other eliminations Total Revenue $ 1,504 $ 2,202 $ 924 $ 1,187 $ 579 $ 408 $ 1,412 $ 8,216 $ 184 $ — $ (10 ) $ 8,390 Energy supply costs — 868 315 322 — 135 853 2,493 2 — — 2,495 Operating expenses 448 609 410 308 167 105 182 2,229 40 28 (10 ) 2,287 Depreciation and amortization 234 272 71 219 192 61 160 1,209 32 2 — 1,243 Operating income 822 453 128 338 220 107 217 2,285 110 (30 ) — 2,365 Other income, net 40 10 7 7 1 3 1 69 1 (10 ) — 60 Finance charges 285 104 41 134 100 40 76 780 6 188 — 974 Income tax expense 139 66 20 55 1 14 22 317 6 (158 ) — 165 Net earnings 438 293 74 156 120 56 120 1,257 99 (70 ) — 1,286 Non-controlling interests 77 — — 1 — — 15 93 27 — — 120 Preference share dividends — — — — — — — — — 66 — 66 Net earnings attributable to common equity shareholders $ 361 $ 293 $ 74 $ 155 $ 120 $ 56 $ 105 $ 1,164 $ 72 $ (136 ) $ — $ 1,100 Goodwill $ 8,369 $ 1,884 $ 615 $ 913 $ 227 $ 235 $ 260 $ 12,503 $ 27 $ — $ — $ 12,530 Total assets 19,798 10,182 3,670 6,815 4,691 2,244 4,119 51,519 1,478 127 (73 ) 53,051 Capital expenditures 998 599 245 486 433 106 300 3,167 44 7 — 3,218 Year Ended December 31, 2017 (in millions) Revenue $ 1,575 $ 2,080 $ 872 $ 1,198 $ 600 $ 398 $ 1,363 $ 8,086 $ 226 $ 1 $ (12 ) $ 8,301 Energy supply costs — 711 260 411 — 142 836 2,360 2 — (1 ) 2,361 Operating expenses 433 609 399 300 198 90 171 2,200 49 12 (11 ) 2,250 Depreciation and amortization 220 260 65 198 190 62 150 1,145 32 2 — 1,179 Operating income 922 500 148 289 212 104 206 2,381 143 (13 ) — 2,511 Other income, net 37 19 5 22 2 2 1 88 1 28 (1 ) 116 Finance charges 259 101 41 116 93 37 74 721 5 189 (1 ) 914 Income tax expense 371 148 42 40 1 14 22 638 19 (69 ) — 588 Net earnings 329 270 70 155 120 55 111 1,110 120 (105 ) — 1,125 Non-controlling interests 57 — — 1 — — 13 71 26 — — 97 Preference share dividends — — — — — — — — — 65 — 65 Net earnings attributable to common equity shareholders $ 272 $ 270 $ 70 $ 154 $ 120 $ 55 $ 98 $ 1,039 $ 94 $ (170 ) $ — $ 963 Goodwill $ 7,698 $ 1,733 $ 566 $ 913 $ 227 $ 235 $ 245 $ 11,617 $ 27 $ — $ — $ 11,644 Total assets 17,581 8,596 3,188 6,418 4,454 2,197 3,814 46,248 1,605 76 (107 ) 47,822 Capital expenditures 982 534 220 446 414 105 302 3,003 21 — — 3,024 |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | REVENUE (in millions) 2018 2017 Electric and gas revenue United States ITC $ 1,539 $ 1,583 UNS Energy 1,993 1,875 Central Hudson 963 814 Canada FortisBC Energy 1,136 1,244 FortisAlberta 554 593 FortisBC Electric 354 347 Newfoundland Power 651 666 Maritime Electric 200 191 FortisOntario 197 197 Caribbean Caribbean Utilities 253 222 FortisTCI 78 71 Total electric and gas revenue 7,918 7,803 Other services revenue (1) 408 395 Revenue from contracts with customers 8,326 8,198 Alternative revenue 16 (46 ) Other revenue 48 149 Total revenue $ 8,390 $ 8,301 (1) Includes $234 million and $217 million from regulated operations for 2018 and 2017 , respectively Revenue from Contracts with Customers Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue, all based on regulator-approved tariff rates. Other services revenue includes: (i) the sale of energy from non-regulated generation operations; (ii) management fee revenue at UNS Energy for the operation of Springerville Units 3 and 4; (iii) revenue from storage optimization activities at Aitken Creek; and (iv) revenue from other services that reflect the ordinary business activities of Fortis' utilities. Alternative Revenue Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria are met. Alternative revenue is recognized on an accrual basis with a corresponding regulatory asset or liability until the revenue is settled. Upon settlement, revenue is not recognized as revenue from contracts with customers but rather as settlement of the regulatory asset or liability on the balance sheet. The Corporation's significant alternative revenue programs are summarized as follows. ITC's formula rates include an annual true-up mechanism that compares actual revenue requirements to billed revenue, and any under- or over-collections are accrued as a regulatory asset or liability and reflected in future rates within a two -year period ( Note 9 ). The formula rates do not require annual regulatory approvals, although inputs remain subject to legal challenge. UNS Energy's lost fixed-cost recovery mechanism ("LFCR") surcharge recovers lost fixed costs, as measured by a reduction in non-fuel revenue, associated with energy efficiency savings and distributed generation. To recover the LFCR regulatory asset, UNS Energy is required to file an annual LFCR adjustment request with the ACC for the LFCR revenue recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of total retail revenue. UNS Energy's demand side management surcharge, which is approved by the ACC annually, compensates for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs, along with a performance incentive, are reflected in non-fuel base rates. At FortisBC Energy and FortisBC Electric, the earnings sharing mechanism allows for a 50 /50 sharing of variances from operating and maintenance expenses and capital expenditures approved as part of the annual revenue requirements. This mechanism is in place until the expiry of the current PBR plan in 2019. Additionally, variances in the forecast versus actual customer-use rate are captured throughout the year in a revenue stabilization adjustment mechanism and a flow-through deferral account, both of which are either refunded to, or recovered from, customers in rates within two years . Other Revenue Other revenue primarily includes gains or losses on energy contract derivatives and lease revenue. |
Accounts Receivable and Other C
Accounts Receivable and Other Current Assets | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Accounts Receivable and Other Current Assets | ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS (in millions) 2018 2017 Trade accounts receivable $ 538 $ 460 Unbilled accounts receivable 575 562 Allowance for doubtful accounts (33 ) (31 ) Total accounts receivable 1,080 991 Income tax receivable 91 8 Other (1) 186 132 $ 1,357 $ 1,131 (1) Consists of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases at FortisBC Energy, and the fair value of derivative instruments (Note 28) |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2018 | |
Inventory Disclosure [Abstract] | |
Inventories | INVENTORIES (in millions) 2018 2017 Materials and supplies $ 280 $ 238 Gas and fuel in storage 87 97 Coal inventory 31 32 $ 398 $ 367 |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | REGULATORY ASSETS AND LIABILITIES (in millions ) 2018 2017 Regulatory assets Deferred income taxes (Notes 3 and 24) $ 1,532 $ 1,403 Employee future benefits (Notes 3 and 25) 485 510 Deferred energy management costs (i) 230 200 Deferred lease costs (ii) 110 104 Deferred operating overhead costs (iii) 103 91 Generation early retirement costs (iv) 98 105 Rate stabilization and related accounts (v) 90 95 Manufactured gas plant site remediation deferral (Note 18) 73 75 Derivatives (Notes 3 and 28) 57 87 Other regulatory assets (vi) 400 375 Total regulatory assets 3,178 3,045 Less: Current portion (324 ) (303 ) Long-term regulatory assets $ 2,854 $ 2,742 Regulatory liabilities Deferred income taxes (Notes 3 and 24) $ 1,574 $ 1,484 Asset removal cost provision (Note 3) 1,169 1,095 Rate stabilization and related accounts (v) 220 254 ROE complaints liability (Note 2) 206 182 Energy efficiency liability (vii) 106 82 Renewable energy surcharge (viii) 85 66 Electric and gas moderator account (ix) 60 58 Employee future benefits (Notes 3 and 25) 37 47 Other regulatory liabilities (vi) 169 178 Total regulatory liabilities 3,626 3,446 Less: Current portion (656 ) (490 ) Long-term regulatory liabilities $ 2,970 $ 2,956 (i) Deferred Energy Management Costs Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through rates, on a straight-line basis over periods ranging from 1 to 10 years . (ii) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") ( Note 17 ). The depreciation of the asset under capital lease and interest expense on the capital lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under BPPA. The annual differences are being deferred as a regulatory asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056. (iii) Deferred Operating Overhead Costs FortisAlberta has deferred certain operating overhead costs for collection in future customer rates over the lives of the related PPE and intangible assets. (iv) Generation Early Retirement Costs UNS Energy holds an undivided interest in the jointly-owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Related retirement costs are being recovered through 2030. UNS Energy owns the Sundt Generating Facility ("Sundt") and plans to early retire Sundt Units 1 and 2 by the end of 2020 as a result of the approved addition of gas-fired generation capacity at Sundt. Capital and operating costs related to Sundt Units 1 and 2 are being recovered through 2028 and 2030, respectively. As a result of these planned early retirements, the associated assets and other related retirement costs were reclassified from PPE to regulatory assets. (v) Rate Stabilization and Related Accounts Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators. Related accounts include the annual true-up mechanism at ITC ( Note 6 ). (vi) Other Regulatory Assets and Liabilities This balance is comprised of regulatory assets and liabilities individually less than $40 million . (vii) Energy Efficiency Liability The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator. (viii) Renewable Energy Surcharge Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through an RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset. The ACC measures RES compliance through Renewable Energy Credits ("REC"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 11) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount. (ix) Electric and Gas Moderator Account Under Central Hudson's 2018 three -year Rate Order certain regulatory assets and liabilities were approved by the PSC for offset and an electric and gas moderator account was established, which will be used for future customer rate moderation. Regulatory assets not earning a return: (i) totalled $1,490 million and $1,464 million as at December 31, 2018 and 2017 , respectively; (ii) are primarily related to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related liabilities that, likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective regulators. |
Assets Held for Sale
Assets Held for Sale | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Assets Held for Sale | ASSETS HELD FOR SALE In 2018 Fortis solicited offers to sell its 51% ownership interest in the Waneta Expansion. In January 2019 the Corporation entered into a definitive agreement with Columbia Power Corporation ("CPC") and Columbia Basin Trust ("CBT") to sell its interest for approximately $1 billion . CPC and CBT, both 100% owned by the Government of British Columbia, are the Corporation's partners and together currently own 49% of the Waneta Expansion. Fortis expects the transaction to close in the second quarter of 2019 following the satisfaction of customary closing conditions. FortisBC Electric will continue to operate the Waneta Expansion facility and purchase its surplus capacity. The related assets and liabilities have been classified as held for sale and are detailed below. (in millions) 2018 Cash $ 15 Accounts receivable and other current assets 3 PPE 718 Intangible assets 30 Total assets held for sale $ 766 Accounts payable and other current liabilities $ 2 Other liabilities 67 Total liabilities associated with assets held for sale $ 69 The non-controlling interest of $324 million remained classified in equity. For both 2018 and 2017, the Waneta Expansion contributed $54 million to earnings before income tax expense, of which 51% is attributable to common equity shareholders. |
Other Assets
Other Assets | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | OTHER ASSETS (in millions) 2018 2017 Supplemental Executive Retirement Plan $ 143 $ 130 Renewable Energy Credits (Note 9 (viii) ) 88 62 Equity investment - BEL 76 73 Equity investment - Wataynikaneyap Partnership 43 22 Other investments 34 29 Defined benefit pension plan (Note 25) 26 31 Deferred compensation plan 26 24 Other (1) 116 109 $ 552 $ 480 (1) Other assets are generally recorded at cost and recovered or amortized over the estimated period of future benefit, where applicable. Other assets also include the fair value of derivatives (Note 28) . ITC, UNS Energy and Central Hudson provide additional post-employment benefits through Supplemental Executive Retirement Plans ("SERPs") and deferred compensation plans for Directors and Officers. The assets held to support these plans are reported separately from the related liabilities (Note 18) . Most plan assets are held in trust and funded mainly through trust-owned life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis (Note 28) . Included in SERP assets are available-for-sale securities at ITC of $72 million ( 2017 - $66 million ), for which gains and losses are recognized in earnings. |
Property, Plant And Equipment
Property, Plant And Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Property, Plant And Equipment | PROPERTY, PLANT AND EQUIPMENT (in millions) Cost Accumulated Depreciation Net Book Value 2018 Distribution Electric $ 10,880 $ (3,076 ) $ 7,804 Gas 4,767 (1,244 ) 3,523 Transmission Electric 14,665 (3,212 ) 11,453 Gas 2,214 (639 ) 1,575 Generation 6,164 (2,279 ) 3,885 Other 3,877 (1,251 ) 2,626 Assets under construction 1,478 — 1,478 Land 310 — 310 $ 44,355 $ (11,701 ) $ 32,654 2017 Distribution Electric $ 9,963 $ (2,864 ) $ 7,099 Gas 4,093 (1,157 ) 2,936 Transmission Electric 12,571 (2,838 ) 9,733 Gas 1,954 (596 ) 1,358 Generation 6,079 (1,996 ) 4,083 Other 3,608 (1,130 ) 2,478 Assets under construction 1,717 — 1,717 Land 264 — 264 $ 40,249 $ (10,581 ) $ 29,668 Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kilovolts ("kV")). These assets include poles, towers and fixtures, low-voltage wires, transformers, overhead and underground conductors, street lighting, meters, metering equipment and other related equipment. Gas distribution assets are those used to transport natural gas at low pressures (generally below 2,070 kilopascals ("kPa")) or a hoop stress of less than 20% of standard minimum yield strength. These assets include distribution stations, telemetry, distribution pipe for mains and services, meter sets and other related equipment. Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires, switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas at higher pressures (generally at 2,070 kPa and higher) or a hoop stress of 20% or more of standard minimum yield strength. These assets include transmission stations, telemetry, transmission pipe and other related equipment. Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems and other related equipment. Other assets include buildings, equipment, vehicles, inventory, information technology assets and the Aitken Creek natural gas storage facility. As at December 31, 2018 , assets under construction were primarily associated with ongoing transmission projects at ITC and the addition of gas-fired generation capacity at UNS Energy. The cost of PPE under capital lease as at December 31, 2018 was $656 million ( December 31, 2017 - $423 million ) and related accumulated depreciation was $203 million ( December 31, 2017 - $176 million ). Jointly-Owned Facilities UNS Energy and ITC hold undivided interests in jointly-owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2018 , interests in jointly-owned facilities consisted of the following. Ownership Accumulated Net Book (in millions, except as noted) % Cost Depreciation Value San Juan Unit 1 50.0 $ 397 $ (183 ) $ 214 Four Corners Units 4 and 5 7.0 239 (104 ) 135 Luna Energy Facility 33.3 79 (5 ) 74 Gila River Common Facilities 25.0 45 (16 ) 29 Springerville Coal Handling Facilities 83.0 284 (117 ) 167 Transmission Facilities 1.0-80.0 1,018 (397 ) 621 $ 2,062 $ (822 ) $ 1,240 |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | INTANGIBLE ASSETS Accumulated Net Book (in millions ) Cost Amortization Value 2018 Computer software $ 860 $ (533 ) $ 327 Land, transmission and water rights 855 (125 ) 730 Other 120 (58 ) 62 Assets under construction 81 — 81 $ 1,916 $ (716 ) $ 1,200 2017 Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 Included in the cost of land, transmission and water rights as at December 31, 2018 was $131 million ( December 31, 2017 - $150 million ) not subject to amortization. Amortization expense was $106 million for 2018 ( 2017 - $ 97 million ). Amortization is estimated to average approximately $81 million for each of the next five years. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | GOODWILL (in millions) 2018 2017 Balance, beginning of year $ 11,644 $ 12,364 Acquisition of ITC — (6 ) Foreign currency translation impacts (1) 886 (714 ) Balance, end of year $ 12,530 $ 11,644 (1) Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and FortisTCI, whose functional currency is the US dollar No goodwill impairment was recognized by the Corporation in 2018 or 2017 . |
Accounts Payable and Other Curr
Accounts Payable and Other Current Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Other Current Liabilities | ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES (in millions) 2018 2017 Trade accounts payable $ 679 $ 696 Gas and fuel cost payable 281 146 Customer and other deposits 267 204 Interest payable 230 223 Accrued taxes other than income taxes 206 178 Dividends payable 199 185 Employee compensation and benefits payable 193 184 Fair value of derivatives (Note 28) 69 71 Manufactured gas plant site remediation (Note 18) 32 35 Defined benefit pension and OPEB liabilities (Note 25) 25 22 Other 108 109 $ 2,289 $ 2,053 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | LONG-TERM DEBT (in millions ) Maturity Date 2018 2017 ITC Secured US First Mortgage Bonds - 4.51% weighted average fixed rate (2017 - 4.67%) 2020-2055 $ 2,652 $ 2,063 Secured US Senior Notes - 4.19% weighted average fixed rate (2017 - 4.19%) 2040-2046 648 596 Unsecured US Senior Notes - 3.91% weighted average fixed rate (2017 - 3.91%) 2020-2043 3,751 3,451 Unsecured US Shareholder Note - 6.00% fixed rate (2017 - 6.00%) 2028 271 250 Unsecured US Term Loan Credit Agreement - 2.03% weighted average variable rate n/a — 63 UNS Energy Unsecured US Tax-Exempt Bonds - 4.66% weighted average fixed and variable rate (2017 - 4.04%) 2020-2040 654 773 Unsecured US Fixed Rate Notes - 4.38% weighted average fixed rate (2017 - 4.26%) 2021-2048 1,943 1,411 Central Hudson Unsecured US Promissory Notes - 4.43% weighted average fixed and variable rate (2017 - 4.28%) 2019-2057 938 770 FortisBC Energy Unsecured Debentures - 5.03% weighted average fixed rate (2017 - 5.13%) 2026-2048 2,595 2,395 FortisAlberta Unsecured Debentures - 4.64% weighted average fixed rate (2017 - 4.70%) 2024-2052 2,185 2,035 FortisBC Electric Secured Debentures - 8.80% fixed rate (2017 - 8.80%) 2023 25 25 Unsecured Debentures - 5.05% weighted average fixed rate (2017 - 5.05%) 2021-2050 710 710 Other Electric Secured First Mortgage Sinking Fund Bonds - 6.14% weighted average fixed rate (2017 - 6.14%) 2020-2057 578 585 Secured First Mortgage Bonds - 5.66% weighted average fixed rate (2017 - 6.19%) 2025-2061 220 195 Unsecured Senior Notes - 4.45% weighted average fixed rate (2017 - 6.11%) 2041-2048 152 104 Unsecured US Senior Loan Notes and Bonds - 4.76% weighted average fixed and variable rate (2017 - 4.80%) 2020-2048 584 525 Corporate Unsecured US Senior Notes and Promissory Notes - 3.41% weighted average fixed rate (2017 - 3.41%) 2019-2044 4,398 4,046 Unsecured Debentures - 6.50% weighted average fixed rate (2017 - 6.50%) 2039 200 200 Unsecured Senior Notes - 2.85% fixed rate (2017 - 2.85%) 2023 500 500 Long-term classification of credit facility borrowings 1,066 671 Fair value adjustment - ITC acquisition 161 167 Total long-term debt (Note 28) 24,231 21,535 Less: Deferred financing costs and debt discounts (146 ) (139 ) Less: Current installments of long-term debt (926 ) (705 ) $ 23,159 $ 20,691 Most long-term debt at the Corporation's regulated utilities is redeemable at the option of the respective utility at the greater of par or a specified price, together with accrued and unpaid interest. Security, if provided, is typically through a fixed or floating first charge on specific assets of the utility. The Corporation's unsecured debentures and senior notes are redeemable at the option of Fortis at the greater of par or a specified price together with accrued and unpaid interest. Certain long-term debt at the Corporation has covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70% of the Corporation's consolidated capital structure. One long-term debt obligation at the Corporation has a covenant which provides that Fortis shall not declare or pay any dividends, other than stock dividends or cumulative preferred dividends on preference shares not issued as stock dividends, make any other distribution on its shares, redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would exceed 75% of its total consolidated capitalization. Long-Term Debt Issuances (in millions, except %) Month Issued Interest Rate (%) Maturity Amount Use of Proceeds ITC First mortgage bonds March 4.00 2053 US 225 (1) (2) (3) (4) First mortgage bonds November 4.32 2051 US 175 (2) (3) (4) UNS Energy Unsecured notes November 4.85 2048 US 300 (1) (4) Central Hudson Unsecured notes June 4.27 2048 US 25 (3) (4) Unsecured notes October 3.99 2026 US 40 (1) (3) (4) Unsecured notes October 4.21 2033 US 40 (1) (3) (4) FortisBC Energy Unsecured debentures December 3.85 2048 200 (2) (4) FortisAlberta Unsecured debentures September 3.73 2048 150 (2) (4) FortisOntario Unsecured notes August 4.10 2048 100 (1) (4) Maritime Electric First mortgage bonds December 4.15 2058 40 (2) (4) FortisTCI Unsecured notes February (5 ) 2023 US 25 (6 ) Unsecured non-revolving term loan (7) September (5 ) 2025 US 5 (4 ) (1) Repay maturing long-term debt (2) Repay credit facility borrowings (3) Finance capital expenditures (4) General corporate purposes (5) Floating rate of a one-month LIBOR plus a spread of 1.75% (6) Repay a hurricane-related emergency standby loan (7) Maximum amount of borrowings under this agreement is US $10 million . Long-Term Debt Repayments The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows. Total (year) (in millions) 2019 $ 926 2020 731 2021 1,324 2022 1,125 2023 1,605 Thereafter 18,520 $ 24,231 Credit Facilities As at December 31, 2018 , the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.2 billion , of which approximately $3.9 billion was unused, including $ 1.0 billion unused under the Corporation's committed revolving corporate credit facility. The following summarizes the credit facilities of the Corporation and its subsidiaries. (in millions) Regulated Corporate 2018 2017 Total credit facilities $ 3,780 $ 1,385 $ 5,165 $ 4,952 Credit facilities utilized: Short-term borrowings (1) (60 ) — (60 ) (209 ) Long-term debt (including current portion) (2) (731 ) (335 ) (1,066 ) (671 ) Letters of credit outstanding (65 ) (54 ) (119 ) (129 ) Credit facilities unutilized $ 2,924 $ 996 $ 3,920 $ 3,943 (1) The weighted average interest rate was approximately 4.2% ( December 31, 2017 - 1.8% ). (2) The weighted average interest rate was approximately 3.3% ( December 31, 2017 - 2.5% ) . The current portion was $735 million ( December 31, 2017 - $312 million ). Credit facilities are syndicated primarily with large banks in Canada and the United States, with no one bank holding more than 20% of the total facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2023 . Consolidated credit facilities of approximately $5.2 billion as at December 31, 2018 are itemized below. (in millions) Amount Maturity Unsecured committed revolving credit facilities Regulated utilities ITC (1) US 900 October 2022 UNS Energy US 500 October 2022 Central Hudson US 250 (2) FortisBC Energy 700 August 2023 FortisAlberta 250 August 2023 FortisBC Electric 150 April 2023 Other Electric 190 (3) Other Electric US 50 January 2020 Corporate and Other 1,350 (4) Other facilities Central Hudson - uncommitted credit facility US 40 n/a FortisBC Electric - unsecured demand overdraft facility 10 n/a Other Electric - unsecured demand facilities 25 n/a Other Electric - unsecured demand facility and emergency standby loan US 60 April 2019 Corporate and Other - unsecured non-revolving facility 35 n/a (1) ITC also has a US $400 million commercial paper program, under which no amounts were outstanding as at December 31, 2018 . (2) US $50 million in July 2020 and US $200 million in October 2020 (3) $50 million in February 2019, $40 million in June 2021, and $100 million in August 2023 (4) $1.3 billion in July 2023, with the option to increase by an amount up to $500 million , and $50 million in April 2021 |
Capital Lease and Finance Oblig
Capital Lease and Finance Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Capital Lease and Finance Obligations | CAPITAL LEASE AND FINANCE OBLIGATIONS Capital Lease Obligations UNS Energy Following the acquisition of Gila River generating station Units 1 and 2 by a third party with whom TEP has a power purchase agreement, TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $224 million (US $164 million ). Over the 20 -month lease term, TEP will pay a monthly demand charge consisting of a capacity charge and an operating fee. For 2018 $10 million ( 2017 - nil ) of demand charges were recognized related to the Gila River Unit 2 capital lease obligation. TEP is party to two Springerville Common Facilities leases with fixed purchase options totalling US $68 million and initial terms to January 2021. TEP has the option to renew the leases for periods of two or more years or exercise the purchase options. Additionally, TEP has entered into agreements with third parties that if the Springerville Common Facilities leases are not renewed, TEP will exercise the purchase options thereunder and the third parties would be obligated to buy a portion of these facilities or continue to make payments to TEP for their use. The Springerville Common Facilities lease obligations bear interest at a six-month LIBOR plus a spread of 2.00% . TEP holds an interest rate swap that effectively fixes the LIBOR rate at 5.77% on $16 million ( December 31, 2017 - $23 million ) of the total lease obligation of $ 19 million ( December 31, 2017 - $26 million ). The swap is recognized as a cash flow hedge (Note 28) . For 2018 $3 million ( 2017 - $4 million ) of interest expense and $8 million ( 2017 - $8 million ) of depreciation expense was recognized related to the Springerville capital lease obligation. FortisBC Electric FortisBC Electric has a capital lease obligation with respect to the operation of the Brilliant hydroelectric plant ("Brilliant Plant") in British Columbia. FortisBC Electric operates and maintains the Brilliant Plant under the BPPA, which expires in 2056, in return for a management fee. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, comprised of the original plant capital charge and periodic upgrade capital charges, which are both subject to fixed annual escalators, as well as sustaining capital charges and operating expenses. The BPPA includes a market-related price adjustment in 2026. Approximately 94% of the output from the Brilliant Plant is purchased by FortisBC Electric through the BPPA. The capital lease obligation bears interest at a composite rate of 5.00% . Included in energy supply costs was $28 million ( 2017 - $27 million ) recognized in accordance with the BPPA, as approved by the BCUC. FortisBC Electric also has a capital lease obligation with respect to the operation of the Brilliant Terminal Station ("BTS") under an agreement, which expires in 2056. The agreement provides that FortisBC Electric will pay a charge related to the recovery of the capital cost of the BTS and related operating costs. The obligation bears interest at a composite rate of 9.00% . Included in operating expenses was $3 million ( 2017 ‑ $3 million ) recognized in accordance with the BTS agreement, as approved by the BCUC. Finance Obligations Between 2000 and 2005 FortisBC Energy entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FortisBC Energy. These assets are integral equipment to real estate assets and the transactions have been accounted for as finance transactions, with the proceeds thereof recognized as finance obligations. Lease payments, net of the portion recognized as interest expense, reduce the finance obligations. The finance obligations have implicit interest rates ranging from 6.90% to 7.48% and are being repaid over an initial 35 -year period with an early termination option after 17 years. If the Company exercises this option, it would pay the municipality an early termination payment equal to the carrying value of the obligation at termination. In October 2018 FortisBC Energy exercised an early termination payment option in the amount $27 million on one of these arrangements. Capital Lease and Finance Obligations Repayments Present values of the minimum lease payments over the next five years and thereafter are as follows. Total (year) (in millions) 2019 $ 313 2020 77 2021 80 2022 49 2023 47 Thereafter 1,885 $ 2,451 Less: Imputed interest and executory costs (1,809 ) Total capital lease and finance obligations 642 Less: Current installments (252 ) $ 390 |
Other Liabilities
Other Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Other Liabilities Disclosure [Abstract] | |
Other Liabilities | OTHER LIABILITIES (in millions) 2018 2017 Defined benefit pension plans (Note 25) $ 391 $ 393 OPEBs (Note 25) 350 381 Asset retirement obligations (Note 3) 111 71 Customer and other deposits 57 67 Stock-based compensation plans (Note 22) 56 39 Mine reclamation obligations (1) 40 40 Manufactured gas plant site remediation (2) 32 34 Fair value of derivatives (Note 28) 30 37 Deferred compensation plan (Note 11) 29 28 Waneta Partnership promissory note (Note 10) — 63 Other (3) 42 57 $ 1,138 $ 1,210 (1) TEP pays ongoing reclamation costs related to three coal mines that supply generating facilities in which it has an ownership interest but does not operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator. TEP's share of the reclamation costs is estimated to be $90 million (US $66 million ) upon expiry of the coal agreements between 2019 and 2031. The present value of the estimated future liability is shown in the table above. (2) Environmental regulations require Central Hudson to investigate sites at which the Company or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. As at December 31, 2018 , an obligation of $64 million (US $47 million ) was recognized, including a current portion of $32 million (US $23 million ) recognized in accounts payable and other current liabilities (Note 15) . Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery ( Note 9 ). (3) Primarily includes long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits. |
Earnings Per Common Share
Earnings Per Common Share | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Common Share | EARNINGS PER COMMON SHARE Diluted earnings per share ("EPS") was calculated using the treasury stock method for options. 2018 2017 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares Shareholders Shares (in millions) (in millions) EPS (in millions) (in millions) EPS Basic EPS $ 1,100 424.7 $ 2.59 $ 963 415.5 $ 2.32 Potential dilutive effect of stock options — 0.5 — 0.7 Diluted EPS $ 1,100 425.2 $ 2.59 $ 963 416.2 $ 2.31 |
Preference Shares
Preference Shares | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Preference Shares | PREFERENCE SHARES Authorized An unlimited number of First Preference Shares and Second Preference Shares, without nominal or par value. Issued and outstanding 2018 2017 First Preference Shares Number Number of Shares Amount of Shares Amount (in thousands) (in millions) (in thousands) (in millions) Series F 5,000 $ 122 5,000 $ 122 Series G 9,200 225 9,200 225 Series H 7,025 172 7,025 172 Series I 2,975 73 2,975 73 Series J 8,000 196 8,000 196 Series K 10,000 244 10,000 244 Series M 24,000 591 24,000 591 66,200 $ 1,623 66,200 $ 1,623 Characteristics of the First Preference Shares are as follows. Earliest Reset Redemption Right to Initial Annual Dividend and/or Redemption Convert on Yield Dividend Yield Conversion Value a One-For- First Preference Shares (1) (2) (%) ($) (%) Option Date ($) One Basis Perpetual fixed rate Series F 4.90 1.2250 — December 1, 2011 25.00 — Series J (3) 4.75 1.1875 — December 1, 2017 25.75 — Fixed rate reset (4) (5) Series G (6) 5.25 1.0983 2.13 September 1, 2013 25.00 — Series H 4.25 0.6250 1.45 June 1, 2015 25.00 Series I Series K 4.00 1.0000 2.05 March 1, 2019 25.00 Series L Series M 4.10 1.0250 2.48 December 1, 2019 25.00 Series N Floating rate reset (5) (7) Series I (3) 2.10 — 1.45 June 1, 2015 25.50 Series H Series L — — 2.05 March 1, 2024 — Series K Series N — — 2.48 December 1, 2024 — Series M (1 ) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal installments on the first day of each quarter. (2 ) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preference Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the First Preference Shares that reset, on every fifth anniversary date thereafter. (3) First Preference Shares, Series J were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date thereafter. (4 ) On the redemption and/or conversion option date, and each five -year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five -year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield. (5) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preference Shares of a specified series. (6) The annual dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023. (7) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield. On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of First and Second Preference Shares and any other class of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution in priority to or ratably with the holders of the common shares. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income | ACCUMULATED OTHER COMPREHENSIVE INCOME (in millions) Opening Balance Net Change Ending Balance 2018 Unrealized foreign currency translation gains (losses) On net investments in foreign operations $ 247 $ 1,223 $ 1,470 On hedges of net investments in foreign operations (172 ) (372 ) (544 ) Income tax (expense) recovery (1 ) 11 10 74 862 936 Other Cash flow hedges (Note 28) 10 1 11 Unrealized employee future benefits (losses) gains (Note 25) (26 ) 6 (20 ) Income tax recovery (expense) 3 (2 ) 1 (13 ) 5 (8 ) Accumulated other comprehensive income $ 61 $ 867 $ 928 2017 Unrealized foreign currency translation gains (losses) On net investments in foreign operations $ 1,227 $ (980 ) $ 247 On hedges of net investments in foreign operations (472 ) 300 (172 ) Income tax recovery (expense) 1 (2 ) (1 ) 756 (682 ) 74 Other Cash flow hedges (Note 28) 8 2 10 Unrealized employee future benefits losses (Note 25) (22 ) (4 ) (26 ) Income tax recovery 3 — 3 (11 ) (2 ) (13 ) Accumulated other comprehensive income $ 745 $ (684 ) $ 61 |
Stock-based Compensation Plans
Stock-based Compensation Plans | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-based Compensation Plans | STOCK-BASED COMPENSATION PLANS Stock Options Officers and certain key employees of Fortis and its subsidiaries are eligible for grants of options to purchase common shares of the Corporation. Options are exercisable for a period of 10 years from the grant date, expire no later than three years after the termination, death or retirement of the optionee, and vest evenly over a four -year period on each anniversary of the grant date. The following options were granted in 2018 and 2017 . 2018 2017 February March February Options granted (#) 721,536 39,972 774,924 Exercise price ($) (1) 41.27 42.00 42.36 Grant date fair value ($) 3.43 4.08 3.22 Valuation assumptions: Dividend yield (%) (2) 3.7 3.7 3.8 Expected volatility (%) (3) 15.5 15.7 16.1 Risk-free interest rate (%) (4) 2.1 2.0 1.2 Weighted average expected life (years) (5) 5.6 5.6 5.6 (1) Five -day VWAP immediately preceding the grant date (2) Reflects average annual dividend yield up to the grant date and the weighted average expected life of the options (3) Reflects historical experience over a period equal to the weighted average expected life of the options (4) Government of Canada benchmark bond yield at the grant date that covers the weighted average expected life of the options (5) Reflects historical experience The following table summarizes information related to stock options for 2018 . Total Options Non-vested Options (1) Number of Options Weighted Average Number of Options Weighted Average Options outstanding, January 1, 2018 3,702,294 $ 36.65 1,812,319 $ 2.86 Granted 761,508 $ 41.31 761,508 $ 3.46 Exercised (357,120 ) $ 33.49 n/a n/a Vested n/a n/a (711,484 ) $ 2.88 Cancelled/Forfeited (91,216 ) $ 40.44 (91,216 ) $ 3.08 Options outstanding, December 31, 2018 4,015,466 $ 37.73 1,771,127 $ 3.10 Options vested, December 31, 2018 (2) 2,244,339 $ 35.40 (1) As at December 31, 2018 , there was $5 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years . (2) As at December 31, 2018 , the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $23 million . The following table summarizes additional stock option information. (in millions) 2018 2017 Stock option expense recognized $ 2 $ 3 Stock options exercised: Cash received for exercise price 12 40 Intrinsic value realized by employees 3 15 Fair value of options that vested 2 2 Directors' DSU Plan Directors of the Corporation who are not officers are eligible for grants of DSUs representing the equity portion of their annual compensation. Directors can further elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also determine that special circumstances justify the grant of additional DSUs to a director. Each DSU vests at the grant date, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash. The following table summarizes information related to DSUs. 2018 2017 Number of Units Beginning of year 184,795 199,411 Granted 32,132 31,453 Notional dividends reinvested 7,518 7,294 Paid out (47,898 ) (53,363 ) End of year 176,547 184,795 Additional Information (in millions) Compensation expense recognized $ 2 $ 3 Cash payout (1) 2 2 Accrued liability as at December 31 (2) 8 9 (1) Reflects a weighted-average payout price of $43.15 per DSU ( 2017 - $45.37 ) (2) Recognized at the respective December 31 st VWAP (Note 3) and included in long-term other liabilities (Note 18) PSU Plans Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of PSUs representing a component of their long-term compensation. Each PSU vests over a three -year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash. At the end of the three -year vesting period, cash payouts are the product of: (i) the numbers of units vested; (ii) the VWAP of the Corporation's common shares for the five trading days prior to the maturity date; and (iii) a payout percentage that may range from 0% to 200% . The payout percentage is based on the Corporation's performance over the three -year vesting period, mainly determined by: (i) the Corporation's total shareholder return as compared to a predefined peer group of companies; and (ii) the Corporation's cumulative EPS, or for certain subsidiaries the Company's cumulative net income, as compared to the target established at the time of the grant. The following table summarizes information related to PSUs. 2018 2017 Number of Units Beginning of year 1,350,960 931,951 Granted 668,995 711,749 Notional dividends reinvested 66,280 44,893 Paid out (280,993 ) (239,509 ) Cancelled/forfeited (42,471 ) (16,910 ) Transferred to RSU Plan — (81,214 ) End of year 1,762,771 1,350,960 Additional Information (in millions) Compensation expense recognized $ 22 $ 26 Compensation expense unrecognized (1) 27 17 Cash payout (2) 14 11 Accrued liability as at December 31 (3) 50 41 Aggregate intrinsic value as at December 31 (4) 77 58 (1) Relates to unvested PSUs and is expected to be recognized over a weighted-average period of two years (2) Reflects a weighted-average payout price of $46.01 per PSU and a payout percentage of 109% ( 2017 - $ 41.46 and 113% , respectively) (3) Recognized at the respective December 31 st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 15 and 18 ) (4) Relates to outstanding PSUs and reflects a weighted-average contractual life of one year RSU Plans Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of RSUs representing a component of their long-term compensation. Each RSU vests over a three -year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash. The following table summarizes information related to RSUs. 2018 2017 Number of Units Beginning of year 482,763 123,612 Granted 305,686 349,496 Notional dividends reinvested 26,263 15,407 Paid out (75,427 ) (74,876 ) Cancelled/forfeited (22,267 ) (12,090 ) Transferred from PSU plan — 81,214 End of year 717,018 482,763 Additional Information (in millions) Compensation expense recognized $ 11 $ 8 Compensation expense unrecognized (1) 15 11 Cash payout (2) 3 3 Accrued liability as at December 31 (3) 19 11 Aggregate intrinsic value as at December 31 (4) 34 22 (1) Relates to unvested RSUs and is expected to be recognized over a weighted-average period of two years (2) Reflects a weighted-average payout price of $45.55 per RSU ( 2017 - $ 43.42 ) (3) Recognized at the respective December 31 st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 15 and 18 ) (4) Relates to outstanding RSUs and reflects a weighted-average contractual life of one year |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | OTHER INCOME, NET (in millions) 2018 2017 Equity component of AFUDC $ 64 $ 74 Interest income 15 14 Equity (loss) income - BEL (1 ) 4 Net periodic pension cost (1 ) (11 ) Net foreign exchange gain (1) — 26 Other (17 ) 9 $ 60 $ 116 (1) Includes a one-time $21 million unrealized foreign exchange gain on US dollar-denominated affiliate loan in 2017 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES Deferred Income Tax Assets and Liabilities The significant components of deferred income tax assets and liabilities consist of the following. (in millions) 2018 2017 Gross deferred income tax assets Regulatory liabilities $ 635 $ 596 Tax loss and credit carryforwards 522 571 Employee future benefits 153 143 Unrealized foreign exchange losses on long-term debt 69 28 Other 76 51 1,455 1,389 Valuation allowance (56 ) (44 ) Net deferred income tax asset $ 1,399 $ 1,345 Gross deferred income tax liabilities PPE $ (3,780 ) $ (3,353 ) Regulatory assets (203 ) (203 ) Intangible assets (102 ) (87 ) (4,085 ) (3,643 ) Net deferred income tax liability $ (2,686 ) $ (2,298 ) The deferred income tax assets associated with unrealized foreign exchange losses on long‑term debt reflect $56 million of unrealized capital losses as at December 31, 2018 ( December 31, 2017 - $44 million ). These deferred income tax assets can only be utilized if the Corporation has capital gains to offset these losses once realized. Management believes that it is more likely than not that Fortis will not be able to generate sufficient future capital gains and, consequently, the Corporation recognized a valuation allowance. Management believes that, based on its historical pattern of taxable income, Fortis will produce the necessary income in the future to realize all other deferred income tax assets. Unrecognized Tax Benefits (in millions) 2018 2017 Beginning of year $ 28 $ 23 Additions related to the current year 6 13 Adjustments related to prior years and U.S. Tax Reform 4 (8 ) End of year $ 38 $ 28 Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2018 . Fortis has no t recognized interest expense in 2018 and 2017 related to unrecognized tax benefits. Income Tax Expense (in millions) 2018 2017 Canadian Earnings before income tax expense $ 376 $ 461 Current income tax 51 41 Deferred income tax (25 ) 16 Total Canadian $ 26 $ 57 Foreign Earnings before income tax expense $ 1,075 $ 1,252 Current income tax (22 ) 3 Deferred income tax 161 528 Total Foreign $ 139 $ 531 Income tax expense $ 165 $ 588 Income tax expense differs from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory income tax rate to earnings before income tax expense. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes. (in millions, except %) 2018 2017 Earnings before income tax expense $ 1,451 $ 1,713 Combined Canadian federal and provincial statutory income tax rate 28.5 % 28.0 % Expected federal and provincial taxes at statutory rate $ 414 $ 480 Increase (decrease) resulting from: Enactment of U.S. Tax Reform (1) — 168 Foreign and other statutory rate differentials (110 ) 31 Remeasurement of deferred tax liabilities (44 ) — AFUDC (14 ) (26 ) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (34 ) (26 ) Items capitalized for accounting purposes but expensed for income tax purposes (21 ) (21 ) Other (26 ) (18 ) Income tax expense $ 165 $ 588 Effective tax rate 11.4 % 34.3 % (1) In 2017 the Tax Cuts and Jobs Act implemented significant changes to U.S. tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21%, effective January 1, 2018. The Corporation's U.S. utilities and holding companies were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment. The one-time remeasurement resulted in an unfavourable earnings impact of $168 million recognized in deferred income tax expense ( $146 million after non-controlling interest). Income Tax Carryforwards (in millions) Expiring Year 2018 Canadian Capital loss n/a $ 59 Non-capital loss 2025-2038 387 Other tax credits 2026-2037 2 448 Unrecognized (15 ) 433 Foreign Federal and state net operating loss 2022-2038 2,130 Other tax credits 2021-2038 115 2,245 Total income tax carryforwards recognized as at December 31 $ 2,678 The Corporation and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal and British Columbia). The Corporation's 2012 to 2018 taxation years are still open for audit in the Canadian jurisdictions and its 2014 to 2018 taxation years are still open for audit in the United States jurisdictions. |
Employee Future Benefits
Employee Future Benefits | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Employee Future Benefits | EMPLOYEE FUTURE BENEFITS For defined benefit pension and OPEB plans, the benefit obligation and fair value of plan assets are measured as at December 31 . For the Corporation's Canadian and Caribbean subsidiaries, actuarial valuations to determine funding contributions for pension plans are required at least every three years. The most recent valuations were as of December 31, 2015 for FortisBC Energy (plan covering non-unionized employees); December 31, 2016 for FortisBC Electric and FortisBC Energy (plans covering unionized employees); December 31, 2017 for Newfoundland Power, FortisAlberta, FortisOntario and the Corporation; and December 31, 2018 for Caribbean Utilities. ITC, UNS Energy and Central Hudson perform annual actuarial valuations as their funding requirements are based on maintaining minimum annual targets, all of which have been met. The Corporation's investment policy is to ensure that the defined benefit pension and OPEB plan assets, together with expected contributions, are invested in a prudent and cost-effective manner to optimally meet the liabilities of the plans. The investment objective is to maximize returns in order to manage the funded status of the plans and minimize the Corporation's cost over the long term, as measured by both cash contributions and recognized expense. Allocation of Plan Assets as at December 31 2018 Target Allocation (weighted-average %) 2018 2017 Equities 46 45 47 Fixed income 47 47 46 Real estate 6 7 6 Cash and other 1 1 1 100 100 100 Fair value of plan assets as at December 31 (in millions) Level 1 (1) Level 2 (1) Level 3 (1) Total 2018 Equities $ 508 $ 885 $ — $ 1,393 Fixed income 144 1,338 — 1,482 Real estate — 14 190 204 Private equities — — 25 25 Cash and other 8 11 — 19 $ 660 $ 2,248 $ 215 $ 3,123 2017 Equities $ 522 $ 949 $ — $ 1,471 Fixed income 133 1,289 — 1,422 Real estate — 13 168 181 Private equities — — 22 22 Cash and other 8 14 — 22 $ 663 $ 2,265 $ 190 $ 3,118 (1) Refer to Note 28 for a description of the fair value hierarchy. The following table reconciles the changes in the fair value of pension plan assets that have been measured using Level 3 inputs. (in millions) 2018 2017 Balance, beginning of year $ 190 $ 113 Return on plan assets 15 12 Foreign currency translation 3 (2 ) Purchases, sales and settlements 7 67 Balance, end of year $ 215 $ 190 Funded Status Defined Benefit OPEB Plans (in millions) 2018 2017 2018 2017 Change in benefit obligation (1) Balance, beginning of year $ 3,215 $ 3,037 $ 665 $ 676 Service costs 84 76 31 27 Employee contributions 16 16 2 2 Interest costs 114 115 23 25 Benefits paid (145 ) (133 ) (26 ) (22 ) Actuarial losses (gains) (217 ) 217 (69 ) (14 ) Past service credits/plan amendments (1 ) — (3 ) (3 ) Foreign currency translation 141 (113 ) 32 (26 ) Balance, end of year (2) $ 3,207 $ 3,215 $ 655 $ 665 Change in value of plan assets Balance, beginning of year $ 2,841 $ 2,646 $ 277 $ 252 Actual return on plan assets (93 ) 336 (13 ) 37 Benefits paid (137 ) (127 ) (26 ) (22 ) Employee contributions 16 16 2 2 Employer contributions 79 69 29 26 Foreign currency translation 124 (99 ) 24 (18 ) Balance, end of year $ 2,830 $ 2,841 $ 293 $ 277 Funded status $ (377 ) $ (374 ) $ (362 ) $ (388 ) Balance sheet presentation Long-term assets (Note 11) $ 26 $ 31 $ 1 $ 3 Current liabilities (Note 15) (12 ) (12 ) (13 ) (10 ) Long-term liabilities (Note 18) (391 ) (393 ) (350 ) (381 ) $ (377 ) $ (374 ) $ (362 ) $ (388 ) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,936 million as at December 31, 2018 ( December 31, 2017 - $2,940 million ). Net Benefit Cost Defined Benefit OPEB Plans (in millions) 2018 2017 2018 2017 Service costs $ 84 $ 76 $ 31 $ 27 Interest costs 114 115 23 25 Expected return on plan assets (162 ) (151 ) (16 ) (14 ) Amortization of actuarial losses 48 45 — 2 Amortization of past service credits/plan amendments — — (10 ) (12 ) Regulatory adjustments (1 ) 2 6 4 Net benefit cost $ 83 $ 87 $ 34 $ 32 The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive income and shows their classification on the consolidated balance sheets. Defined Benefit Pension Plans OPEB Plans (in millions) 2018 2017 2018 2017 Unamortized net actuarial losses (gains) $ 19 $ 22 $ (2 ) $ — Unamortized past service costs 1 1 2 3 Income tax recovery (3 ) (5 ) (1 ) (1 ) Accumulated other comprehensive income (Note 21) $ 17 $ 18 $ (1 ) $ 2 Net actuarial losses (gains) $ 457 $ 443 $ (25 ) $ 17 Past service credits (10 ) (11 ) (16 ) (23 ) Other regulatory deferrals 15 10 27 27 $ 462 $ 442 $ (14 ) $ 21 Regulatory assets (Note 9) $ 462 $ 442 $ 23 $ 68 Regulatory liabilities (Note 9) — — (37 ) (47 ) Net regulatory assets $ 462 $ 442 $ (14 ) $ 21 The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income. Defined Benefit Pension Plans OPEB Plans (in millions) 2018 2017 2018 2017 Current year net actuarial (gains) losses $ (3 ) $ 5 $ (2 ) $ (1 ) Past service (credits) costs/plan amendments — — (1 ) 2 Amortization of actuarial losses (1 ) (1 ) — — Foreign currency translation 1 (1 ) — — Income tax recovery 2 — — — Total recognized in comprehensive income $ (1 ) $ 3 $ (3 ) $ 1 Current year net actuarial losses (gains) $ 41 $ 24 $ (39 ) $ (35 ) Past service credits/plan amendments — — (3 ) (5 ) Amortization of actuarial losses (47 ) (44 ) — (1 ) Amortization of past service (costs) credits 1 — 11 12 Foreign currency translation 21 (17 ) (3 ) 2 Regulatory adjustments 4 (1 ) (1 ) (6 ) Total recognized in regulatory assets $ 20 $ (38 ) $ (35 ) $ (33 ) Net actuarial losses of $1 million are expected to be amortized to net benefit cost from accumulated other comprehensive income in 2019 related to defined benefit pension plans. Net actuarial losses of $24 million , past service credits of $1 million and regulatory adjustments of $1 million are expected to be amortized to net benefit cost from regulatory assets in 2019 related to defined benefit pension plans. Past service credits of $8 million , net actuarial gains of $4 million and regulatory adjustments of $4 million are expected to be amortized to net benefit cost from regulatory assets in 2019 related to OPEB plans. Significant Assumptions Defined Benefit OPEB Plans (weighted-average %) 2018 2017 2018 2017 Discount rate during the year (1) 3.56 3.98 3.57 3.96 Discount rate as at December 31 4.07 3.58 4.13 3.59 Expected long-term rate of return on plan assets (2) 5.80 5.97 5.48 5.81 Rate of compensation increase 3.35 3.34 — — Health care cost trend increase as at December 31 (3) — — 4.61 4.71 (1) ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach. (2) Developed by management with assistance from external actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. (3) The projected 2019 weighted-average health care cost trend rate for OPEB plans is 6.35% and is assumed to decrease over the next 14 years to the weighted-average ultimate health care cost trend rate of 4.61% in 2032 and thereafter. The following table summarizes for 2018 the effects of changing the health care cost trend rate by 1%. (in millions) 1% increase 1% decrease Increase (decrease) in accumulated benefit obligation $ 85 $ (67 ) Increase (decrease) in service and interest costs 11 (8 ) Defined Benefit Expected Benefit Payments Pension Payments OPEB (year) (in millions) (in millions) 2019 $ 147 $ 26 2020 152 28 2021 157 30 2022 165 32 2023 170 33 2024-2028 946 185 During 2019 the Corporation expects to contribute $47 million for defined benefit pension plans and $31 million for OPEB plans. In 2018 the Corporation expensed $38 million ( 2017 - $38 million ) related to defined contribution pension plans. |
Terminated Acquisition
Terminated Acquisition | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Terminated Acquisition | TERMINATED ACQUISITION In May 2017 Fortis had entered into an agreement with Teck Resources Limited to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer in this regard. Consequently, the purchase agreement with Fortis was terminated, resulting in the payment of a $ 28 million break fee to Fortis, which was recognized in operating expenses. |
Supplementary Cash Flow Informa
Supplementary Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Cash Flow Information | SUPPLEMENTARY CASH FLOW INFORMATION (in millions) 2018 2017 Cash paid for Interest $ 969 $ 927 Income taxes 73 69 Change in working capital Accounts receivable and other current assets $ (204 ) $ (74 ) Prepaid expenses 1 (3 ) Inventories (8 ) (6 ) Regulatory assets - current portion 16 39 Accounts payable and other current liabilities 99 119 Regulatory liabilities - current portion (6 ) (172 ) $ (102 ) $ (97 ) Non-cash investing and financing activities Accrued capital expenditures $ 328 $ 307 Common share dividends reinvested 272 253 Gila River generating station Unit 2 capital lease 223 — Contributions in aid of construction 14 35 Exercise of stock options into common shares 1 5 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments and Risk Management | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments and Risk Management | FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Derivatives The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivatives at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception. Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows. Cash flows associated with the settlement of all derivatives are included in operating activities in the consolidated statements of cash flows. Energy contracts subject to regulatory deferral UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values were measured primarily under the market approach using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses. Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values were measured using forward pricing provided by independent third-party information. FortisBC Energy holds gas supply contracts and financial commodity swaps to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash flows based on published market prices and forward natural gas curves. Unrealized gains or losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. As at December 31, 2018 , unrealized losses of $57 million ( December 31, 2017 - $87 million ) were recognized as regulatory assets and unrealized gains of $9 million ( December 31, 2017 - $2 million ) were recognized in regulatory liabilities (Note 9) . Energy contracts not subject to regulatory deferral UNS Energy holds wholesale trading contracts that qualify as derivatives to fix power prices and realize potential margin, of which 10% of any realized gains are shared with customers through rate stabilization accounts. Fair values were measured using a market approach using independent third-party information, where possible. Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, capture natural gas price spreads, and manage the financial risk posed by physical transactions. Fair values were measured using forward pricing from published market sources. Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in earnings. During 2018 unrealized losses of $12 million ( 2017 - unrealized gains of $36 million ) were recognized in revenue. Foreign exchange contracts The Corporation holds US dollar foreign exchange contracts to mitigate exposure to volatility of foreign exchange rates. The contracts expire in 2019 and have a combined notional amount of $161 million . Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in earnings. During 2018 unrealized losses of $11 million ( 2017 - unrealized gains of $3 million ) were recognized in other income, net. Interest rate and total return swaps UNS Energy holds an interest rate swap to mitigate exposure to volatility in variable interest rates on capital lease obligations (Note 17) . The swap expires in 2020 and has a notional amount of $16 million . Fair value was measured using an income valuation approach based on six-month LIBOR. Unrealized gains and losses associated with changes in the fair value of this interest rate swap, which was designated as a cash flow hedge, are recognized in other comprehensive income and reclassified to earnings through interest expense over the life of the hedged debt. The loss expected to be reclassified to earnings within the next 12 months is estimated to be approximately $3 million , net of tax. The Corporation holds three total return swaps to manage the cash flow risk associated with forecasted future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $41 million and terms ranging from one to three years , expiring in January 2019 , 2020 and 2021 . Fair value was measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in the fair value of the total return swaps are recognized in earnings. During 2018 unrealized gains of less than $1 million ( 2017 - unrealized losses of less than $1 million ) were recognized in other income, net. Other investments ITC, UNS Energy and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees. These investments consist of mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active markets. Gains and losses on these funds are recognized in earnings. During 2018 unrealized gains of less than $1 million ( 2017 - unrealized gains of less than $1 million ) were recognized in other income, net. Recurring Fair Value Measures The following table presents the fair value of the assets and liabilities that are accounted for at fair value on a recurring basis. (in millions) Level 1 (1) Level 2 (1) Level 3 (1) Total As at December 31, 2018 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 33 $ 8 $ 41 Energy contracts not subject to regulatory deferral (2) — 13 3 16 Other investments (4) 155 — — 155 $ 155 $ 46 $ 11 $ 212 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ — $ (86 ) $ (3 ) $ (89 ) Energy contracts not subject to regulatory deferral (5) — (1 ) — (1 ) Foreign exchange contracts, interest rate and total return swaps (6) (8 ) (1 ) — (9 ) $ (8 ) $ (88 ) $ (3 ) $ (99 ) As at December 31, 2017 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 19 $ 2 $ 21 Energy contracts not subject to regulatory deferral (2) — 26 4 30 Foreign exchange contracts (6) 3 — — 3 Other investments (4) 78 — — 78 $ 81 $ 45 $ 6 $ 132 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ (1 ) $ (103 ) $ (2 ) $ (106 ) Energy contracts not subject to regulatory deferral (5) — — (1 ) (1 ) Interest rate and total return swaps (6) — (1 ) — (1 ) $ (1 ) $ (104 ) $ (3 ) $ (108 ) (1) Under the hierarchy, fair value is determined using: (i) level 1 - unadjusted quoted prices in active markets; (ii) level 2 - other pricing inputs directly or indirectly observable in the marketplace; and (iii) level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the fair value measurement. (2) Included in accounts receivable and other current assets or other assets (3) Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of long-term wholesale trading contracts and certain gas swap contracts. (4) Included in other assets (5) Included in accounts payable and other current liabilities or other liabilities (6) Included in accounts receivable and other current assets, accounts payable and other current liabilities or other liabilities Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one hierarchical fair value level to another. There were no transfers between levels during 2018 . For level 3 measurements, changes in the unobservable inputs could have a significant impact on fair value. Excluding long-term wholesale trading contracts and certain gas swap contracts, the impacts of fair value changes are subject to regulatory recovery. The following table reconciles changes in the fair value of level 3 net assets and liabilities. (in millions) 2018 2017 Balance, beginning of year $ 3 $ 2 Realized gains (losses) 14 (13 ) Settlements (9 ) 12 Transfers of assets out of level 3 — (2 ) Transfers of liabilities out of level 3 — 4 Balance, end of year $ 8 $ 3 The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following table presents the potential offset of counterparty netting. Energy Contracts Gross Amount Recognized on Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/Posted Net Amount As at December 31, 2018 Derivative assets $ 57 $ 28 $ 16 $ 13 Derivative liabilities (90 ) (28 ) — (62 ) As at December 31, 2017 Derivative assets $ 51 $ 17 $ 7 $ 27 Derivative liabilities (107 ) (17 ) — (90 ) Volume of Derivative Activity As at December 31, 2018 , the Corporation had various energy contracts that will settle on various dates through 2029. The volumes related to electricity and natural gas derivatives are outlined below. As at December 31 2018 2017 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 774 1,291 Electricity power purchase contracts (GWh) 651 761 Gas swap contracts (PJ) 203 216 Gas supply contract premiums (PJ) 266 219 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 1,440 2,387 Gas swap contracts (PJ) 37 36 (1) GWh means gigawatt hours and PJ means petajoules. Credit Risk For cash equivalents, accounts receivable and other current assets, and long-term other receivables, credit risk is generally limited to the carrying value on the consolidated balance sheets. The Corporation's subsidiaries generally have a large and diversified customer base, which minimizes the concentration of credit risk. Policies in place to minimize credit risk include requiring customer deposits, prepayments and/or credit checks for certain customers, performing disconnections and/or using third-party collection agencies for overdue accounts. ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. Credit risk is limited as such customers have investment-grade credit ratings. ITC further reduces credit risk by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors. FortisAlberta has a concentration of credit risk as distribution service billings are to a relatively small group of retailers. The Company reduces its exposure by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating. UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non‑performance by counterparties to derivatives. Credit risk is limited by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS Energy and Central Hudson, certain contractual arrangements require counterparties to post collateral. The value of derivatives in net liability positions under contracts with credit risk-related contingent features that, if triggered, could require the posting of a like amount of collateral was $75 million as at December 31, 2018 ( December 31, 2017 - $57 million ). Foreign Exchange Hedge The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar. The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased this exposure by designating US dollar-denominated borrowings at the corporate level as a hedge of its net investment in foreign subsidiaries. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of US dollar-denominated subsidiary earnings. As at December 31, 2018 , US $3,441 million ( December 31, 2017 - US $3,385 million ) of net investment in foreign subsidiaries was hedged by the Corporation's corporately issued US dollar-denominated long-term debt and approximately US $7,970 million ( December 31, 2017 - US $7,548 million ) was unhedged. Exchange rate fluctuations associated with the hedged net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive income. Financial Instruments Not Carried at Fair Value Excluding long-term debt, the consolidated carrying value of the Corporation's financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature. As at December 31, 2018 , the carrying value of long-term debt, including the current portion, was $24,231 million ( December 31, 2017 - $ 21,535 million ) (Note 16) compared to an estimated fair value of $25,110 million ( December 31, 2017 - $23,481 million ). Long-term debt is fair valued using level 2 inputs. The fair value of long-term debt is calculated using quoted market prices or, when unavailable, by either: (i) discounting the associated future cash flows at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt with similar maturities. Since the Corporation does not intend to settle the long-term debt prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability. |
Variable Interest Entity
Variable Interest Entity | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable Interest Entity | VARIABLE INTEREST ENTITY The Waneta Partnership, which owns and operates the Waneta Expansion on the Pend d'Oreille River in British Columbia, is 51% owned by Fortis and 49% by CPC and CBT (Note 10) . The Waneta Expansion is operated and maintained by a wholly owned subsidiary of the Corporation and the output is sold to BC Hydro and FortisBC Electric under 40 -year contracts. Each partner pays its proportionate share of the costs and is entitled to a proportionate share of the net revenue. The Corporation's ownership interest is a variable interest entity. Fortis is the primary beneficiary as it has the power to direct the activities of the partnership, the obligation to absorb losses and the right to receive benefits that could be significant to the partnership. Consequently, Fortis consolidates the Waneta Partnership. The Corporation's consolidated financial statements include the following with respect to the Waneta Partnership. (in millions) 2018 2017 Assets Cash and cash equivalents $ 15 $ 16 Accounts receivable and other current assets 15 14 PPE 674 688 Intangible assets 30 30 $ 734 $ 748 Liabilities Accounts payable and other current liabilities $ (6 ) $ (28 ) Other liabilities (67 ) (63 ) (73 ) (91 ) Net assets before partners' equity $ 661 $ 657 Revenue $ 94 $ 93 Expenses Operating expenses 18 17 Depreciation and amortization 18 18 Finance charges 4 4 40 39 Net earnings $ 54 $ 54 Cash used in investing activities at the Waneta Partnership for 2018 included capital expenditures of $27 million ( 2017 - $5 million ). Cash flow related to financing activities for 2018 included dividends paid by the Waneta Partnership to non-controlling interests of $35 million ( 2017 - $34 million ) and advances from non-controlling interests of $11 million ( 2017 - nil ). |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES As at December 31, 2018 , consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term debt and capital lease and finance obligations separately disclosed in Notes 16 and 17 , respectively, were as follows. (in millions) Total Due within 1 year Due in year 2 Due in year 3 Due in year 4 Due in year 5 Due after Interest obligations on long-term debt $ 16,345 $ 994 $ 973 $ 950 $ 902 $ 870 $ 11,656 Power purchase obligations (1) 2,438 254 191 174 170 172 1,477 Renewable power purchase obligations (2) 1,699 110 110 109 109 108 1,153 Gas purchase obligations (3) 1,348 359 290 242 202 144 111 Long-term contracts - UNS Energy (4) 777 176 142 92 60 46 261 ITC easement agreement (5) 436 14 14 14 14 14 366 Renewable energy credit purchase agreements (6) 146 24 26 18 11 11 56 Debt collection agreement (7) 119 3 3 3 3 3 104 Purchase of Springerville Common Facilities (8) 93 — — 93 — — — Joint-use asset and shared service agreements 52 3 3 3 3 3 37 Operating lease obligations 51 8 6 5 4 4 24 Other (9) 530 108 84 89 38 36 175 Total $ 24,034 $ 2,053 $ 1,842 $ 1,792 $ 1,516 $ 1,411 $ 15,420 (1) The most significant power purchase obligations are described below. Maritime Electric ( $771 million ): includes an agreement entitling Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and requiring Maritime Electric to pay its share of the station's capital operating costs for the life of the unit. Maritime Electric also has two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2024. FortisOntario ( $705 million ) : an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually from January 2020 through December 2030. FortisBC Energy ( $522 million ): an agreement with BC Hydro for the supply of electricity to the Tilbury liquefied natural gas facility expansion. FortisBC Electric ($ 345 million ) : includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20 -year term beginning October 1, 2013. (2) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require them to purchase 100% of the output of certain renewable energy generating facilities once commercial operation is achieved. Amounts shown are the estimated future payments. (3) Certain of the Corporation's subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2018 . (4) UNS Energy enters into long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas transportation services to meet load requirements, and the purchase of transmission services for purchased power. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates between 2019 and 2040. (5) ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licences associated with the land over which its transmission lines cross. The agreement expires in December 2050, subject to 10 potential 50 -year renewals thereafter. (6) UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations or other renewable generators. Payments are primarily made at contractually agreed-upon intervals based on metered energy production. (7) Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick transmission system interconnection. Payments under the agreement, which expires in February 2056, will be collected from customers in future rates. (8) UNS Energy is obligated to purchase an undivided 32.2% interest in the Springerville Common Facilities if the related two leases are not renewed. The initial lease terms expire in January 2021 (Note 17) . (9) Includes stock-based compensation plan obligations, land easements, asset retirement obligations, and defined benefit pension plan funding obligations. Other Commitments The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Their capital expenditures are largely to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth. Consolidated capital expenditures are forecast to be approximately $ 3.7 billion for 2019 and approximately $17.3 billion over the five-year period from 2019 through 2023 . Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects totalling $2.3 billion (US$ 1.7 billion ) . Central Hudson's maximum commitment is $248 million (US$ 182 million ), for which it has issued a parental guarantee. As at December 31, 2018 , there was no obligation under this guarantee. As at December 31, 2018 , FHI had $77 million ( December 31, 2017 - $80 million ) of parental guarantees outstanding to support storage optimization activities at Aitken Creek. Contingency In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia Supreme Court by the Coldwater Indian Band ("Band") regarding interests in a pipeline right of way on reserve lands. The pipeline was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in 2007. The Band seeks cancellation of the right of way and damages for wrongful interference with the Band’s use and enjoyment of reserve lands. In May 2016 the Federal Court dismissed the Band’s application for judicial review of the ministerial consent. In September 2017 the Federal Court of Appeal set aside the Minister’s consent and returned the matter to the Minister for redetermination. No amount has been accrued as the outcome cannot yet be reasonably determined. |
Comparative Figures
Comparative Figures | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Comparative Figures | COMPARATIVE FIGURES Effective January 1, 2018, the Corporation elected to present, on the statement of cash flows, all borrowings and repayments under committed credit facilities on a gross basis and continue to present borrowings and repayments under uncommitted or demand credit facilities on a net basis as Net Change in Short-Term Borrowings. The presentation change resulted in $365 million , which was previously reported within Net Repayments and Borrowings under Committed Facilities, being reported on a gross basis, with (i) $4,376 million reported as Borrowings under Committed Credit Facilities, (ii) $5,441 million reported as Repayments under Committed Credit Facilities, and (iii) $700 million reported as Net Change in Short-Term Borrowings. Comparative figures were reclassified to conform with the revised segmentation, as described in Note 5 , and to reflect the retrospective adoption of ASU 2017-07, as described in Note 3 . |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated. These consolidated financial statements include the accounts of the Corporation and its subsidiaries and controlled variable interest entity. They reflect the equity method of accounting for entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated entities. Intercompany transactions have been eliminated, except for transactions between non-regulated and regulated entities in accordance with US GAAP for rate-regulated entities. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts Fortis and each subsidiary, other than ITC, maintains an allowance for doubtful accounts that is estimated based on a variety of factors, including receivables aging, historical experience, specific events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible accounts based upon their specific identification. Accounts receivable are written off in the period in which they are deemed uncollectible. |
Inventories | Inventories Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable value. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or 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 will be, or are expected to be, refunded to customers through the rate-setting process. Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory approval. |
Investments | Investments Investments accounted for using the equity method are reviewed annually for potential impairment in value. Impairments are recognized when identified. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE. Depreciation rates of the Corporation's regulated utilities include a provision for estimated future asset removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability ( Note 9 ) against which actual asset removal costs are netted when incurred . Most of the Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon derecognition, any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain or loss is recognized as it is expected that such amounts will be reflected in future depreciation expense when they are refunded or collected in customer rates. Through methodologies established by their respective regulators, most of the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure program; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC totalling $31 million ( 2017 - $38 million ) is reported as a reduction of finance charges and the equity component is reported as other income (Note 23) . Both components are charged to earnings through depreciation expense over the estimated service lives of the applicable PPE. At FortisAlberta the cost of PPE includes required contributions to the Alberta Electric System Operator ("AESO") toward funding the construction of transmission facilities. Excluding UNS Energy, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulator, UNS Energy recognizes such items as inventory until used and reclassifies them to PPE once put into service. Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are capitalized. PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are approved by the respective regulators. Depreciation rates for 2018 ranged from 0.9% to 34.6% ( 2017 - 0.9% to 34.6% ). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.5% for 2018 ( 2017 – 2.6% ). The service life ranges and weighted average remaining service life of the Corporation's PPE as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 33 Gas 14-95 35 14-95 34 Transmission Electric 20-90 42 20-80 41 Gas 5-85 41 5-80 34 Generation 1-85 24 5-85 28 Other 3-70 15 3-70 14 |
Leases | Leases Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the present value of the minimum lease payments. Capital leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting purposes, in which case the timing of the expense recognition will conform to the regulator's requirements. Operating lease payments are recognized as an expense on a straight-line basis over the lease term. |
Intangible Assets | Intangible Assets Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite. Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether the indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively. Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 50.0% for 2018 ( 2017 – 1.0% to 50.0% ). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-90 57 36-80 57 Other 10-100 13 10-100 10 Most of the Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use. Upon derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization. No gain or loss is recognized as it is expected that such amounts will be reflected in future amortization costs when they are refunded or collected in customer rates. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the carrying value may not exceed the total undiscounted cash flows expected to be generated by the asset. If that is determined to be the case, the asset is written down to estimated fair value and an impairment loss is recognized. |
Goodwill | Goodwill Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions. Impairment testing is performed if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. If that is determined to be the case, goodwill is written down to estimated fair value and an impairment loss is recognized. Otherwise, Fortis performs an annual assessment for each of the 11 reporting units having goodwill. The primary method for estimating the fair value of reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value method. The income approach uses underlying estimates and assumptions with varying degrees of uncertainty, including the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation method, the market approach, as well as a reconciliation of the total estimated fair value of all reporting units to the Corporation's market capitalization, are also performed and compared to the results of the income approach. |
Deferred Financing Costs | Deferred Financing Costs Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt. |
Employee Future Benefits | Employee Future Benefits Fortis and its subsidiaries each maintains one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post-employment benefit ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The costs of defined contribution pension plans are expensed as incurred. For defined benefit pension plans and OPEB plans, the projected or accumulated benefit obligation and net benefit costs are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and, for OPEB plans, expected health care costs. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension or OPEB payments. Defined benefit pension plan and OPEB plan assets are recognized at fair value. For the purpose of determining defined benefit pension cost, FortisBC Energy and Newfoundland Power use the market-related value whereby investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years . The excess of any cumulative net actuarial gain or loss over 10% of the greater of: (i) the projected or accumulated benefit obligation; and (ii) the fair value or market-related value, as applicable, of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees. The net funded or unfunded status of defined benefit pension and OPEB plans, measured as the difference between the fair value of the plan assets and the projected or accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheets. For most of the Corporation's regulated utilities, any difference between defined benefit pension or OPEB plan costs ordinarily recognized under US GAAP and those recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in future rates ( Note 9 ). For most of the Corporation's regulated utilities, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment ( Note 9 ). |
Stock-Based Compensation | Stock-Based Compensation Compensation expense related to stock options is measured at the grant date using the Black-Scholes fair value option-pricing model and each grant is amortized to compensation expense as a single award evenly over the four -year vesting period, with the offsetting entry to additional paid-in capital. Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock. Fortis recognizes liabilities associated with its Directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans, all representing cash-settled awards, at fair value at each reporting date until settlement. The fair value of these liabilities is based on the five -day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP as at December 31, 2018 was $45.14 ( December 31, 2017 - $46.01 ). The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with the defined metrics of each grant and management's best estimate. Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the lesser of three years or the period to retirement eligibility and for the DSU Plan is at the time of grant. Forfeitures are accounted for as they occur. |
Foreign Currency Translation | Foreign Currency Translation Assets and liabilities of the Corporation's foreign operations, all of which have a US dollar functional currency, are translated at the exchange rate in effect at the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income. The exchange rate as at December 31, 2018 was US$1.00=CAD$ 1.36 ( December 31, 2017 – US$1.00=CAD$ 1.25 ). Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CAD$ 1.30 for 2018 ( 2017 - US$1.00=CAD$ 1.30 ). Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Translation gains and losses are recognized in earnings. Translation gains and losses on foreign currency-denominated debt that is designated as an effective hedge of foreign net investments are recognized in other comprehensive income. |
Derivative and Hedging | Derivatives and Hedging Derivatives Not Designated as Hedges Derivatives not designated as hedges are used by: (i) Fortis, to manage cash flow risk associated with forecast US dollar cash inflows and forecast future cash settlements of DSU and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions. These derivatives are measured at fair value with changes thereto recognized in earnings. Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the respective regulators. These derivatives are measured at fair value with changes thereto recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 9) . Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in earnings as energy supply costs. Derivatives Designated as Hedges The Corporation, ITC and UNS Energy use cash flow hedges to manage interest rate risk. Unrealized gains and losses are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings. Any hedge ineffectiveness is immediately recognized in earnings. The Corporation's earnings from, and net investments in, foreign subsidiaries and equity-accounted investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through US dollar-denominated debt at the corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated other comprehensive income. Presentation of Derivatives The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivatives are presented in operating activities in the consolidated statements of cash flows. |
Income Taxes | Income Taxes The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year. Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes that are more likely than not to be realized. They are measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation allowances are recognized when it is more likely than not that all, or a portion of, a deferred income tax asset will not be realized. Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta reflect current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and, for certain regulatory balances, deferred income tax. Caribbean Utilities, FortisTCI and, for the 50 -year term of its power purchase agreements, BECOL are not subject to income tax. Differences between the income tax expense or recovery recognized under US GAAP and that reflected in current customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities ( Note 9 ). At FortisAlberta the capital cost allowance pool for certain PPE for rate-setting purposes is different from that prescribed for Canadian tax filing purposes. In a future reporting period yet to be determined, the difference may result in reported income tax expense exceeding that reflected in customer rates. Fortis does not recognize deferred income taxes on temporary differences related to investments in foreign subsidiaries where it intends to indefinitely reinvest earnings. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $2.3 billion as at December 31, 2018 ( December 31, 2017 - $561 million ). If such earnings are repatriated, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is impractical. Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement. Income tax interest and penalties are recognized as income tax expense when incurred. |
Asset Retirement Obligations | Asset Retirement Obligations The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, right-of-ways and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized. Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 18) if a reasonable estimate of fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated over the useful life of the asset. Actual settlement costs are recognized as a reduction in the accrued liability. |
Contingencies | Contingencies Fortis and its subsidiaries are involved in certain legal and environmental matters that arise in the normal course of business. Management makes judgments regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss, or range of loss, is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a regulatory asset is also recognized. Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required. However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over long time periods. Actual outcomes may differ materially from the amounts recognized. |
New Accounting Policies | New Accounting Policies Revenue Recognition Effective January 1, 2018, Fortis adopted Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , which clarifies the principles for recognizing revenue and requires additional disclosures ( Note 6 ). Fortis adopted this standard using the modified retrospective approach, under which comparative periods are not restated and the cumulative impact is recognized at the date of adoption, supplemented by additional disclosures. Upon adoption, there were no adjustments to the opening balance of retained earnings. Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is allocated to unsatisfied performance obligations. Revenue is generally measured in kilowatt hours, gigajoules or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load. FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the AESO. This includes the collection of transmission revenue from its customers, which occurs through the transmission component of its regulator-approved rates. FortisAlberta reports transmission revenue and expenses on a net basis. Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that has not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known. Generation revenue from non-regulated operations is recognized on delivery at contracted fixed or market rates. Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration, including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is certain . Revenue excludes sales and municipal taxes collected from customers. Prior to the adoption of ASC 606, Central Hudson recognized sales tax and FortisAlberta recognized municipal tax on a gross basis in both revenue and expense. The exclusion of these taxes from revenue resulted in a decrease in revenue of $ 49 million for 2018 compared to 2017 . The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal payment plans as the period between the transfer of energy to customers and the customers' payment will be less than one year. Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations ( Note 5 ). This represents the level of disaggregation used by the Corporation's President and Chief Executive Officer ("CEO") to allocate resources and evaluate performance. Financial Instruments Effective January 1, 2018, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities . Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the equity method to be measured at fair value through earnings; however, entities may elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and liabilities to be presented separately in the financial statement notes, grouped by measurement category and form. Adoption did not impact these consolidated financial statements. Pension and Post-Retirement Benefit Costs Effective January 1, 2018, the Corporation adopted ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost , which requires current service costs to be grouped in the statement of earnings with other employee compensation costs arising from services rendered. The remaining components of net periodic benefit costs must be presented separately and outside of operating income. Additionally, only the service cost component can be capitalized. On adoption, the Corporation applied the presentation guidance retrospectively and the capitalization guidance prospectively. This resulted in a retrospective $11 million reclassification from Operating Expenses to Other Income, Net in the consolidated financial statements. Leases ASU No. 2016-02, Leases ("ASC 842"), issued in February 2016, is effective for Fortis January 1, 2019 and is to be applied using a modified retrospective approach or an optional transition method with implementation options, referred to as practical expedients. Principally, it requires balance sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating leases, along with additional disclosures. Fortis has selected the optional transition method, which allows entities to continue to apply the current lease guidance in the comparative periods presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance. Fortis elected a package of practical expedients that allowed it to not reassess the lease classification of existing leases or whether existing contracts, including land easements, are or contain a lease. Finally, Fortis utilized the hindsight practical expedient to determine the lease term. Upon adoption, Fortis will recognize right-of-use assets and corresponding lease liabilities of approximately $50 million for operating leases primarily related to office facilities and utility property. Operating leases related to vehicles and office equipment were identified and quantified as immaterial. Fortis has not identified an adjustment to opening retained earnings, and there will be no impact on earnings or cash flows. Fortis implemented changes to processes and control activities related to monitoring the adoption of ASC 842 and made changes to accounting policies associated with accounting for lease assets and liabilities, and related income and expense, as of January 1, 2019. Financial Instruments ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments , issued in June 2016, is effective for Fortis January 1, 2020 and is to be applied on a modified retrospective basis. Principally, it requires entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to estimate credit losses. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures. Hedging ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities , issued in August 2017, is effective for Fortis January 1, 2019. Principally, it better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. For cash flow and net investment hedges that existed at the date of adoption, the amendments were applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to opening retained earnings. Amended presentation and disclosure guidance was applied prospectively. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures. Fair Value Measurement Disclosures ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, issued in August 2018, is effective for Fortis January 1, 2020 and is to be primarily applied on a retrospective basis, with certain disclosures requiring prospective application. Principally, it improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements. In addition, the amendment removes (a) the amount of, and reasons for, transfers between level 2 and level 3 of the fair value hierarchy, (b) the policy for timing of transfers between levels, and (c) the valuation processes for level 3 fair value measurements. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosures. Pensions and Other Post-Retirement Plan Disclosures ASU No. 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans , issued in August 2018, is effective for Fortis January 1, 2021 and is to be applied on a retrospective basis for all periods presented. Principally, it modifies the disclosure requirements for employers with defined pension or other post-retirement plans and clarifies disclosure requirements. In addition, the amendments remove (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period, (b) the amount and timing of plan assets expected to be returned to the employer, and (c) the effects of a one-percentage-point change on the assumed health care costs and the change in rates on service cost, interest cost and the benefit obligation for post-retirement health care benefits. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosure. |
Use of Accounting Estimates | Use of Accounting Estimates The preparation of these consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments, including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities, revenues, expenses, gains and losses. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments being recognized in the period they become known. Actual results may differ significantly from these estimates. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of Property Plant and Equipment | The service life ranges and weighted average remaining service life of the Corporation's PPE as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 33 Gas 14-95 35 14-95 34 Transmission Electric 20-90 42 20-80 41 Gas 5-85 41 5-80 34 Generation 1-85 24 5-85 28 Other 3-70 15 3-70 14 (in millions) Cost Accumulated Depreciation Net Book Value 2018 Distribution Electric $ 10,880 $ (3,076 ) $ 7,804 Gas 4,767 (1,244 ) 3,523 Transmission Electric 14,665 (3,212 ) 11,453 Gas 2,214 (639 ) 1,575 Generation 6,164 (2,279 ) 3,885 Other 3,877 (1,251 ) 2,626 Assets under construction 1,478 — 1,478 Land 310 — 310 $ 44,355 $ (11,701 ) $ 32,654 2017 Distribution Electric $ 9,963 $ (2,864 ) $ 7,099 Gas 4,093 (1,157 ) 2,936 Transmission Electric 12,571 (2,838 ) 9,733 Gas 1,954 (596 ) 1,358 Generation 6,079 (1,996 ) 4,083 Other 3,608 (1,130 ) 2,478 Assets under construction 1,717 — 1,717 Land 264 — 264 $ 40,249 $ (10,581 ) $ 29,668 |
Intangible Assets | The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-90 57 36-80 57 Other 10-100 13 10-100 10 Accumulated Net Book (in millions ) Cost Amortization Value 2018 Computer software $ 860 $ (533 ) $ 327 Land, transmission and water rights 855 (125 ) 730 Other 120 (58 ) 62 Assets under construction 81 — 81 $ 1,916 $ (716 ) $ 1,200 2017 Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 |
Segmented Information (Tables)
Segmented Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Schedule of significant inter-company transactions | Inter-company balances, transactions and profit are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. Inter-company transactions are summarized below. (in millions) 2018 2017 Sale of capacity from Waneta Expansion to FortisBC Electric $ 47 $ 46 Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy 25 24 |
Schedule of Information by Reportable Segment | REGULATED NON-REGULATED Year Ended Energy Inter- December 31, 2018 UNS Central FortisBC Fortis FortisBC Other Sub Infra- Corporate segment (in millions) ITC Energy Hudson Energy Alberta Electric Electric total structure and Other eliminations Total Revenue $ 1,504 $ 2,202 $ 924 $ 1,187 $ 579 $ 408 $ 1,412 $ 8,216 $ 184 $ — $ (10 ) $ 8,390 Energy supply costs — 868 315 322 — 135 853 2,493 2 — — 2,495 Operating expenses 448 609 410 308 167 105 182 2,229 40 28 (10 ) 2,287 Depreciation and amortization 234 272 71 219 192 61 160 1,209 32 2 — 1,243 Operating income 822 453 128 338 220 107 217 2,285 110 (30 ) — 2,365 Other income, net 40 10 7 7 1 3 1 69 1 (10 ) — 60 Finance charges 285 104 41 134 100 40 76 780 6 188 — 974 Income tax expense 139 66 20 55 1 14 22 317 6 (158 ) — 165 Net earnings 438 293 74 156 120 56 120 1,257 99 (70 ) — 1,286 Non-controlling interests 77 — — 1 — — 15 93 27 — — 120 Preference share dividends — — — — — — — — — 66 — 66 Net earnings attributable to common equity shareholders $ 361 $ 293 $ 74 $ 155 $ 120 $ 56 $ 105 $ 1,164 $ 72 $ (136 ) $ — $ 1,100 Goodwill $ 8,369 $ 1,884 $ 615 $ 913 $ 227 $ 235 $ 260 $ 12,503 $ 27 $ — $ — $ 12,530 Total assets 19,798 10,182 3,670 6,815 4,691 2,244 4,119 51,519 1,478 127 (73 ) 53,051 Capital expenditures 998 599 245 486 433 106 300 3,167 44 7 — 3,218 Year Ended December 31, 2017 (in millions) Revenue $ 1,575 $ 2,080 $ 872 $ 1,198 $ 600 $ 398 $ 1,363 $ 8,086 $ 226 $ 1 $ (12 ) $ 8,301 Energy supply costs — 711 260 411 — 142 836 2,360 2 — (1 ) 2,361 Operating expenses 433 609 399 300 198 90 171 2,200 49 12 (11 ) 2,250 Depreciation and amortization 220 260 65 198 190 62 150 1,145 32 2 — 1,179 Operating income 922 500 148 289 212 104 206 2,381 143 (13 ) — 2,511 Other income, net 37 19 5 22 2 2 1 88 1 28 (1 ) 116 Finance charges 259 101 41 116 93 37 74 721 5 189 (1 ) 914 Income tax expense 371 148 42 40 1 14 22 638 19 (69 ) — 588 Net earnings 329 270 70 155 120 55 111 1,110 120 (105 ) — 1,125 Non-controlling interests 57 — — 1 — — 13 71 26 — — 97 Preference share dividends — — — — — — — — — 65 — 65 Net earnings attributable to common equity shareholders $ 272 $ 270 $ 70 $ 154 $ 120 $ 55 $ 98 $ 1,039 $ 94 $ (170 ) $ — $ 963 Goodwill $ 7,698 $ 1,733 $ 566 $ 913 $ 227 $ 235 $ 245 $ 11,617 $ 27 $ — $ — $ 11,644 Total assets 17,581 8,596 3,188 6,418 4,454 2,197 3,814 46,248 1,605 76 (107 ) 47,822 Capital expenditures 982 534 220 446 414 105 302 3,003 21 — — 3,024 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Revenue | (in millions) 2018 2017 Electric and gas revenue United States ITC $ 1,539 $ 1,583 UNS Energy 1,993 1,875 Central Hudson 963 814 Canada FortisBC Energy 1,136 1,244 FortisAlberta 554 593 FortisBC Electric 354 347 Newfoundland Power 651 666 Maritime Electric 200 191 FortisOntario 197 197 Caribbean Caribbean Utilities 253 222 FortisTCI 78 71 Total electric and gas revenue 7,918 7,803 Other services revenue (1) 408 395 Revenue from contracts with customers 8,326 8,198 Alternative revenue 16 (46 ) Other revenue 48 149 Total revenue $ 8,390 $ 8,301 (1) Includes $234 million and $217 million from regulated operations for 2018 and 2017 , respectively |
Accounts Receivable and Other_2
Accounts Receivable and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Schedule Of Accounts Receivable and Other Current Assets | (in millions) 2018 2017 Trade accounts receivable $ 538 $ 460 Unbilled accounts receivable 575 562 Allowance for doubtful accounts (33 ) (31 ) Total accounts receivable 1,080 991 Income tax receivable 91 8 Other (1) 186 132 $ 1,357 $ 1,131 (1) Consists of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases at FortisBC Energy, and the fair value of derivative instruments (Note 28) |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Inventory Disclosure [Abstract] | |
Schedule of Utility Inventory | (in millions) 2018 2017 Materials and supplies $ 280 $ 238 Gas and fuel in storage 87 97 Coal inventory 31 32 $ 398 $ 367 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | (in millions ) 2018 2017 Regulatory assets Deferred income taxes (Notes 3 and 24) $ 1,532 $ 1,403 Employee future benefits (Notes 3 and 25) 485 510 Deferred energy management costs (i) 230 200 Deferred lease costs (ii) 110 104 Deferred operating overhead costs (iii) 103 91 Generation early retirement costs (iv) 98 105 Rate stabilization and related accounts (v) 90 95 Manufactured gas plant site remediation deferral (Note 18) 73 75 Derivatives (Notes 3 and 28) 57 87 Other regulatory assets (vi) 400 375 Total regulatory assets 3,178 3,045 Less: Current portion (324 ) (303 ) Long-term regulatory assets $ 2,854 $ 2,742 Regulatory liabilities Deferred income taxes (Notes 3 and 24) $ 1,574 $ 1,484 Asset removal cost provision (Note 3) 1,169 1,095 Rate stabilization and related accounts (v) 220 254 ROE complaints liability (Note 2) 206 182 Energy efficiency liability (vii) 106 82 Renewable energy surcharge (viii) 85 66 Electric and gas moderator account (ix) 60 58 Employee future benefits (Notes 3 and 25) 37 47 Other regulatory liabilities (vi) 169 178 Total regulatory liabilities 3,626 3,446 Less: Current portion (656 ) (490 ) Long-term regulatory liabilities $ 2,970 $ 2,956 (i) Deferred Energy Management Costs Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through rates, on a straight-line basis over periods ranging from 1 to 10 years . (ii) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") ( Note 17 ). The depreciation of the asset under capital lease and interest expense on the capital lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under BPPA. The annual differences are being deferred as a regulatory asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056. (iii) Deferred Operating Overhead Costs FortisAlberta has deferred certain operating overhead costs for collection in future customer rates over the lives of the related PPE and intangible assets. (iv) Generation Early Retirement Costs UNS Energy holds an undivided interest in the jointly-owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Related retirement costs are being recovered through 2030. UNS Energy owns the Sundt Generating Facility ("Sundt") and plans to early retire Sundt Units 1 and 2 by the end of 2020 as a result of the approved addition of gas-fired generation capacity at Sundt. Capital and operating costs related to Sundt Units 1 and 2 are being recovered through 2028 and 2030, respectively. As a result of these planned early retirements, the associated assets and other related retirement costs were reclassified from PPE to regulatory assets. (v) Rate Stabilization and Related Accounts Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators. Related accounts include the annual true-up mechanism at ITC ( Note 6 ). (vi) Other Regulatory Assets and Liabilities This balance is comprised of regulatory assets and liabilities individually less than $40 million . |
Schedule of Regulatory Liabilities | (in millions ) 2018 2017 Regulatory assets Deferred income taxes (Notes 3 and 24) $ 1,532 $ 1,403 Employee future benefits (Notes 3 and 25) 485 510 Deferred energy management costs (i) 230 200 Deferred lease costs (ii) 110 104 Deferred operating overhead costs (iii) 103 91 Generation early retirement costs (iv) 98 105 Rate stabilization and related accounts (v) 90 95 Manufactured gas plant site remediation deferral (Note 18) 73 75 Derivatives (Notes 3 and 28) 57 87 Other regulatory assets (vi) 400 375 Total regulatory assets 3,178 3,045 Less: Current portion (324 ) (303 ) Long-term regulatory assets $ 2,854 $ 2,742 Regulatory liabilities Deferred income taxes (Notes 3 and 24) $ 1,574 $ 1,484 Asset removal cost provision (Note 3) 1,169 1,095 Rate stabilization and related accounts (v) 220 254 ROE complaints liability (Note 2) 206 182 Energy efficiency liability (vii) 106 82 Renewable energy surcharge (viii) 85 66 Electric and gas moderator account (ix) 60 58 Employee future benefits (Notes 3 and 25) 37 47 Other regulatory liabilities (vi) 169 178 Total regulatory liabilities 3,626 3,446 Less: Current portion (656 ) (490 ) Long-term regulatory liabilities $ 2,970 $ 2,956 (i) Deferred Energy Management Costs Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through rates, on a straight-line basis over periods ranging from 1 to 10 years . (ii) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") ( Note 17 ). The depreciation of the asset under capital lease and interest expense on the capital lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under BPPA. The annual differences are being deferred as a regulatory asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056. (iii) Deferred Operating Overhead Costs FortisAlberta has deferred certain operating overhead costs for collection in future customer rates over the lives of the related PPE and intangible assets. (iv) Generation Early Retirement Costs UNS Energy holds an undivided interest in the jointly-owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Related retirement costs are being recovered through 2030. UNS Energy owns the Sundt Generating Facility ("Sundt") and plans to early retire Sundt Units 1 and 2 by the end of 2020 as a result of the approved addition of gas-fired generation capacity at Sundt. Capital and operating costs related to Sundt Units 1 and 2 are being recovered through 2028 and 2030, respectively. As a result of these planned early retirements, the associated assets and other related retirement costs were reclassified from PPE to regulatory assets. (v) Rate Stabilization and Related Accounts Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators. Related accounts include the annual true-up mechanism at ITC ( Note 6 ). (vi) Other Regulatory Assets and Liabilities This balance is comprised of regulatory assets and liabilities individually less than $40 million . (vii) Energy Efficiency Liability The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator. (viii) Renewable Energy Surcharge Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through an RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset. The ACC measures RES compliance through Renewable Energy Credits ("REC"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 11) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount. (ix) Electric and Gas Moderator Account Under Central Hudson's 2018 three -year Rate Order certain regulatory assets and liabilities were approved by the PSC for offset and an electric and gas moderator account was established, which will be used for future customer rate moderation. |
Assets Held for Sale (Tables)
Assets Held for Sale (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Schedule of Asset Held for Sale | (in millions) 2018 Cash $ 15 Accounts receivable and other current assets 3 PPE 718 Intangible assets 30 Total assets held for sale $ 766 Accounts payable and other current liabilities $ 2 Other liabilities 67 Total liabilities associated with assets held for sale $ 69 |
Other Assets (Tables)
Other Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of Other Assets | (in millions) 2018 2017 Supplemental Executive Retirement Plan $ 143 $ 130 Renewable Energy Credits (Note 9 (viii) ) 88 62 Equity investment - BEL 76 73 Equity investment - Wataynikaneyap Partnership 43 22 Other investments 34 29 Defined benefit pension plan (Note 25) 26 31 Deferred compensation plan 26 24 Other (1) 116 109 $ 552 $ 480 (1) Other assets are generally recorded at cost and recovered or amortized over the estimated period of future benefit, where applicable. Other assets also include the fair value of derivatives (Note 28) . |
Property, Plant And Equipment (
Property, Plant And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Schedule of Property Plant and Equipment | The service life ranges and weighted average remaining service life of the Corporation's PPE as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 33 Gas 14-95 35 14-95 34 Transmission Electric 20-90 42 20-80 41 Gas 5-85 41 5-80 34 Generation 1-85 24 5-85 28 Other 3-70 15 3-70 14 (in millions) Cost Accumulated Depreciation Net Book Value 2018 Distribution Electric $ 10,880 $ (3,076 ) $ 7,804 Gas 4,767 (1,244 ) 3,523 Transmission Electric 14,665 (3,212 ) 11,453 Gas 2,214 (639 ) 1,575 Generation 6,164 (2,279 ) 3,885 Other 3,877 (1,251 ) 2,626 Assets under construction 1,478 — 1,478 Land 310 — 310 $ 44,355 $ (11,701 ) $ 32,654 2017 Distribution Electric $ 9,963 $ (2,864 ) $ 7,099 Gas 4,093 (1,157 ) 2,936 Transmission Electric 12,571 (2,838 ) 9,733 Gas 1,954 (596 ) 1,358 Generation 6,079 (1,996 ) 4,083 Other 3,608 (1,130 ) 2,478 Assets under construction 1,717 — 1,717 Land 264 — 264 $ 40,249 $ (10,581 ) $ 29,668 |
Schedule of Jointly-Owned Facilities | As at December 31, 2018 , interests in jointly-owned facilities consisted of the following. Ownership Accumulated Net Book (in millions, except as noted) % Cost Depreciation Value San Juan Unit 1 50.0 $ 397 $ (183 ) $ 214 Four Corners Units 4 and 5 7.0 239 (104 ) 135 Luna Energy Facility 33.3 79 (5 ) 74 Gila River Common Facilities 25.0 45 (16 ) 29 Springerville Coal Handling Facilities 83.0 284 (117 ) 167 Transmission Facilities 1.0-80.0 1,018 (397 ) 621 $ 2,062 $ (822 ) $ 1,240 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Indefinite-Lived Intangible Assets | Accumulated Net Book (in millions ) Cost Amortization Value 2018 Computer software $ 860 $ (533 ) $ 327 Land, transmission and water rights 855 (125 ) 730 Other 120 (58 ) 62 Assets under construction 81 — 81 $ 1,916 $ (716 ) $ 1,200 2017 Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 |
Schedule of Finite-Lived Intangible Assets | The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2018 2017 (years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-90 57 36-80 57 Other 10-100 13 10-100 10 Accumulated Net Book (in millions ) Cost Amortization Value 2018 Computer software $ 860 $ (533 ) $ 327 Land, transmission and water rights 855 (125 ) 730 Other 120 (58 ) 62 Assets under construction 81 — 81 $ 1,916 $ (716 ) $ 1,200 2017 Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | (in millions) 2018 2017 Balance, beginning of year $ 11,644 $ 12,364 Acquisition of ITC — (6 ) Foreign currency translation impacts (1) 886 (714 ) Balance, end of year $ 12,530 $ 11,644 (1) Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and FortisTCI, whose functional currency is the US dollar |
Accounts Payable and Other Cu_2
Accounts Payable and Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other Accrued Liabilities | (in millions) 2018 2017 Trade accounts payable $ 679 $ 696 Gas and fuel cost payable 281 146 Customer and other deposits 267 204 Interest payable 230 223 Accrued taxes other than income taxes 206 178 Dividends payable 199 185 Employee compensation and benefits payable 193 184 Fair value of derivatives (Note 28) 69 71 Manufactured gas plant site remediation (Note 18) 32 35 Defined benefit pension and OPEB liabilities (Note 25) 25 22 Other 108 109 $ 2,289 $ 2,053 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | (in millions, except %) Month Issued Interest Rate (%) Maturity Amount Use of Proceeds ITC First mortgage bonds March 4.00 2053 US 225 (1) (2) (3) (4) First mortgage bonds November 4.32 2051 US 175 (2) (3) (4) UNS Energy Unsecured notes November 4.85 2048 US 300 (1) (4) Central Hudson Unsecured notes June 4.27 2048 US 25 (3) (4) Unsecured notes October 3.99 2026 US 40 (1) (3) (4) Unsecured notes October 4.21 2033 US 40 (1) (3) (4) FortisBC Energy Unsecured debentures December 3.85 2048 200 (2) (4) FortisAlberta Unsecured debentures September 3.73 2048 150 (2) (4) FortisOntario Unsecured notes August 4.10 2048 100 (1) (4) Maritime Electric First mortgage bonds December 4.15 2058 40 (2) (4) FortisTCI Unsecured notes February (5 ) 2023 US 25 (6 ) Unsecured non-revolving term loan (7) September (5 ) 2025 US 5 (4 ) (1) Repay maturing long-term debt (2) Repay credit facility borrowings (3) Finance capital expenditures (4) General corporate purposes (5) Floating rate of a one-month LIBOR plus a spread of 1.75% (6) Repay a hurricane-related emergency standby loan (7) Maximum amount of borrowings under this agreement is US $10 million . (in millions ) Maturity Date 2018 2017 ITC Secured US First Mortgage Bonds - 4.51% weighted average fixed rate (2017 - 4.67%) 2020-2055 $ 2,652 $ 2,063 Secured US Senior Notes - 4.19% weighted average fixed rate (2017 - 4.19%) 2040-2046 648 596 Unsecured US Senior Notes - 3.91% weighted average fixed rate (2017 - 3.91%) 2020-2043 3,751 3,451 Unsecured US Shareholder Note - 6.00% fixed rate (2017 - 6.00%) 2028 271 250 Unsecured US Term Loan Credit Agreement - 2.03% weighted average variable rate n/a — 63 UNS Energy Unsecured US Tax-Exempt Bonds - 4.66% weighted average fixed and variable rate (2017 - 4.04%) 2020-2040 654 773 Unsecured US Fixed Rate Notes - 4.38% weighted average fixed rate (2017 - 4.26%) 2021-2048 1,943 1,411 Central Hudson Unsecured US Promissory Notes - 4.43% weighted average fixed and variable rate (2017 - 4.28%) 2019-2057 938 770 FortisBC Energy Unsecured Debentures - 5.03% weighted average fixed rate (2017 - 5.13%) 2026-2048 2,595 2,395 FortisAlberta Unsecured Debentures - 4.64% weighted average fixed rate (2017 - 4.70%) 2024-2052 2,185 2,035 FortisBC Electric Secured Debentures - 8.80% fixed rate (2017 - 8.80%) 2023 25 25 Unsecured Debentures - 5.05% weighted average fixed rate (2017 - 5.05%) 2021-2050 710 710 Other Electric Secured First Mortgage Sinking Fund Bonds - 6.14% weighted average fixed rate (2017 - 6.14%) 2020-2057 578 585 Secured First Mortgage Bonds - 5.66% weighted average fixed rate (2017 - 6.19%) 2025-2061 220 195 Unsecured Senior Notes - 4.45% weighted average fixed rate (2017 - 6.11%) 2041-2048 152 104 Unsecured US Senior Loan Notes and Bonds - 4.76% weighted average fixed and variable rate (2017 - 4.80%) 2020-2048 584 525 Corporate Unsecured US Senior Notes and Promissory Notes - 3.41% weighted average fixed rate (2017 - 3.41%) 2019-2044 4,398 4,046 Unsecured Debentures - 6.50% weighted average fixed rate (2017 - 6.50%) 2039 200 200 Unsecured Senior Notes - 2.85% fixed rate (2017 - 2.85%) 2023 500 500 Long-term classification of credit facility borrowings 1,066 671 Fair value adjustment - ITC acquisition 161 167 Total long-term debt (Note 28) 24,231 21,535 Less: Deferred financing costs and debt discounts (146 ) (139 ) Less: Current installments of long-term debt (926 ) (705 ) $ 23,159 $ 20,691 |
Schedule of Long-Term Debt Repayments | The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows. Total (year) (in millions) 2019 $ 926 2020 731 2021 1,324 2022 1,125 2023 1,605 Thereafter 18,520 $ 24,231 |
Schedule of Credit Facilities | The following summarizes the credit facilities of the Corporation and its subsidiaries. (in millions) Regulated Corporate 2018 2017 Total credit facilities $ 3,780 $ 1,385 $ 5,165 $ 4,952 Credit facilities utilized: Short-term borrowings (1) (60 ) — (60 ) (209 ) Long-term debt (including current portion) (2) (731 ) (335 ) (1,066 ) (671 ) Letters of credit outstanding (65 ) (54 ) (119 ) (129 ) Credit facilities unutilized $ 2,924 $ 996 $ 3,920 $ 3,943 (1) The weighted average interest rate was approximately 4.2% ( December 31, 2017 - 1.8% ). (2) The weighted average interest rate was approximately 3.3% ( December 31, 2017 - 2.5% ) . The current portion was $735 million ( December 31, 2017 - $312 million ). Consolidated credit facilities of approximately $5.2 billion as at December 31, 2018 are itemized below. (in millions) Amount Maturity Unsecured committed revolving credit facilities Regulated utilities ITC (1) US 900 October 2022 UNS Energy US 500 October 2022 Central Hudson US 250 (2) FortisBC Energy 700 August 2023 FortisAlberta 250 August 2023 FortisBC Electric 150 April 2023 Other Electric 190 (3) Other Electric US 50 January 2020 Corporate and Other 1,350 (4) Other facilities Central Hudson - uncommitted credit facility US 40 n/a FortisBC Electric - unsecured demand overdraft facility 10 n/a Other Electric - unsecured demand facilities 25 n/a Other Electric - unsecured demand facility and emergency standby loan US 60 April 2019 Corporate and Other - unsecured non-revolving facility 35 n/a (1) ITC also has a US $400 million commercial paper program, under which no amounts were outstanding as at December 31, 2018 . (2) US $50 million in July 2020 and US $200 million in October 2020 (3) $50 million in February 2019, $40 million in June 2021, and $100 million in August 2023 (4) $1.3 billion in July 2023, with the option to increase by an amount up to $500 million , and $50 million in April 2021 |
Capital Lease and Finance Obl_2
Capital Lease and Finance Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Schedule of Repayment of Capital Lease and Finance Obligations | Present values of the minimum lease payments over the next five years and thereafter are as follows. Total (year) (in millions) 2019 $ 313 2020 77 2021 80 2022 49 2023 47 Thereafter 1,885 $ 2,451 Less: Imputed interest and executory costs (1,809 ) Total capital lease and finance obligations 642 Less: Current installments (252 ) $ 390 |
Other Liabilities (Tables)
Other Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Liabilities Disclosure [Abstract] | |
Schedule of Other Liabilities | (in millions) 2018 2017 Defined benefit pension plans (Note 25) $ 391 $ 393 OPEBs (Note 25) 350 381 Asset retirement obligations (Note 3) 111 71 Customer and other deposits 57 67 Stock-based compensation plans (Note 22) 56 39 Mine reclamation obligations (1) 40 40 Manufactured gas plant site remediation (2) 32 34 Fair value of derivatives (Note 28) 30 37 Deferred compensation plan (Note 11) 29 28 Waneta Partnership promissory note (Note 10) — 63 Other (3) 42 57 $ 1,138 $ 1,210 (1) TEP pays ongoing reclamation costs related to three coal mines that supply generating facilities in which it has an ownership interest but does not operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator. TEP's share of the reclamation costs is estimated to be $90 million (US $66 million ) upon expiry of the coal agreements between 2019 and 2031. The present value of the estimated future liability is shown in the table above. (2) Environmental regulations require Central Hudson to investigate sites at which the Company or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. As at December 31, 2018 , an obligation of $64 million (US $47 million ) was recognized, including a current portion of $32 million (US $23 million ) recognized in accounts payable and other current liabilities (Note 15) . Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery ( Note 9 ). (3) Primarily includes long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits. |
Earnings Per Common Share (Tabl
Earnings Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of Net Earnings to Common Shareholders | Diluted earnings per share ("EPS") was calculated using the treasury stock method for options. 2018 2017 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares Shareholders Shares (in millions) (in millions) EPS (in millions) (in millions) EPS Basic EPS $ 1,100 424.7 $ 2.59 $ 963 415.5 $ 2.32 Potential dilutive effect of stock options — 0.5 — 0.7 Diluted EPS $ 1,100 425.2 $ 2.59 $ 963 416.2 $ 2.31 |
Preference Shares (Tables)
Preference Shares (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Schedule of Preference Shares Issued and Outstanding | Issued and outstanding 2018 2017 First Preference Shares Number Number of Shares Amount of Shares Amount (in thousands) (in millions) (in thousands) (in millions) Series F 5,000 $ 122 5,000 $ 122 Series G 9,200 225 9,200 225 Series H 7,025 172 7,025 172 Series I 2,975 73 2,975 73 Series J 8,000 196 8,000 196 Series K 10,000 244 10,000 244 Series M 24,000 591 24,000 591 66,200 $ 1,623 66,200 $ 1,623 Characteristics of the First Preference Shares are as follows. Earliest Reset Redemption Right to Initial Annual Dividend and/or Redemption Convert on Yield Dividend Yield Conversion Value a One-For- First Preference Shares (1) (2) (%) ($) (%) Option Date ($) One Basis Perpetual fixed rate Series F 4.90 1.2250 — December 1, 2011 25.00 — Series J (3) 4.75 1.1875 — December 1, 2017 25.75 — Fixed rate reset (4) (5) Series G (6) 5.25 1.0983 2.13 September 1, 2013 25.00 — Series H 4.25 0.6250 1.45 June 1, 2015 25.00 Series I Series K 4.00 1.0000 2.05 March 1, 2019 25.00 Series L Series M 4.10 1.0250 2.48 December 1, 2019 25.00 Series N Floating rate reset (5) (7) Series I (3) 2.10 — 1.45 June 1, 2015 25.50 Series H Series L — — 2.05 March 1, 2024 — Series K Series N — — 2.48 December 1, 2024 — Series M (1 ) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal installments on the first day of each quarter. (2 ) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preference Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the First Preference Shares that reset, on every fifth anniversary date thereafter. (3) First Preference Shares, Series J were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date thereafter. (4 ) On the redemption and/or conversion option date, and each five -year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five -year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield. (5) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preference Shares of a specified series. (6) The annual dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023. (7) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield. |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Change in Accumulated Other Comprehensive Income by Category | (in millions) Opening Balance Net Change Ending Balance 2018 Unrealized foreign currency translation gains (losses) On net investments in foreign operations $ 247 $ 1,223 $ 1,470 On hedges of net investments in foreign operations (172 ) (372 ) (544 ) Income tax (expense) recovery (1 ) 11 10 74 862 936 Other Cash flow hedges (Note 28) 10 1 11 Unrealized employee future benefits (losses) gains (Note 25) (26 ) 6 (20 ) Income tax recovery (expense) 3 (2 ) 1 (13 ) 5 (8 ) Accumulated other comprehensive income $ 61 $ 867 $ 928 2017 Unrealized foreign currency translation gains (losses) On net investments in foreign operations $ 1,227 $ (980 ) $ 247 On hedges of net investments in foreign operations (472 ) 300 (172 ) Income tax recovery (expense) 1 (2 ) (1 ) 756 (682 ) 74 Other Cash flow hedges (Note 28) 8 2 10 Unrealized employee future benefits losses (Note 25) (22 ) (4 ) (26 ) Income tax recovery 3 — 3 (11 ) (2 ) (13 ) Accumulated other comprehensive income $ 745 $ (684 ) $ 61 |
Stock-based Compensation Plans
Stock-based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Stock Option Information | The following options were granted in 2018 and 2017 . 2018 2017 February March February Options granted (#) 721,536 39,972 774,924 Exercise price ($) (1) 41.27 42.00 42.36 Grant date fair value ($) 3.43 4.08 3.22 Valuation assumptions: Dividend yield (%) (2) 3.7 3.7 3.8 Expected volatility (%) (3) 15.5 15.7 16.1 Risk-free interest rate (%) (4) 2.1 2.0 1.2 Weighted average expected life (years) (5) 5.6 5.6 5.6 (1) Five -day VWAP immediately preceding the grant date (2) Reflects average annual dividend yield up to the grant date and the weighted average expected life of the options (3) Reflects historical experience over a period equal to the weighted average expected life of the options (4) Government of Canada benchmark bond yield at the grant date that covers the weighted average expected life of the options (5) Reflects historical experience |
Summary of Stock Option Activity | The following table summarizes information related to stock options for 2018 . Total Options Non-vested Options (1) Number of Options Weighted Average Number of Options Weighted Average Options outstanding, January 1, 2018 3,702,294 $ 36.65 1,812,319 $ 2.86 Granted 761,508 $ 41.31 761,508 $ 3.46 Exercised (357,120 ) $ 33.49 n/a n/a Vested n/a n/a (711,484 ) $ 2.88 Cancelled/Forfeited (91,216 ) $ 40.44 (91,216 ) $ 3.08 Options outstanding, December 31, 2018 4,015,466 $ 37.73 1,771,127 $ 3.10 Options vested, December 31, 2018 (2) 2,244,339 $ 35.40 (1) As at December 31, 2018 , there was $5 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years . (2) As at December 31, 2018 , the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $23 million . |
Schedule of Additional Stock Option Information | The following table summarizes additional stock option information. (in millions) 2018 2017 Stock option expense recognized $ 2 $ 3 Stock options exercised: Cash received for exercise price 12 40 Intrinsic value realized by employees 3 15 Fair value of options that vested 2 2 |
DSU Plan Activity | The following table summarizes information related to DSUs. 2018 2017 Number of Units Beginning of year 184,795 199,411 Granted 32,132 31,453 Notional dividends reinvested 7,518 7,294 Paid out (47,898 ) (53,363 ) End of year 176,547 184,795 Additional Information (in millions) Compensation expense recognized $ 2 $ 3 Cash payout (1) 2 2 Accrued liability as at December 31 (2) 8 9 (1) Reflects a weighted-average payout price of $43.15 per DSU ( 2017 - $45.37 ) (2) Recognized at the respective December 31 st VWAP (Note 3) and included in long-term other liabilities (Note 18) |
PSU Plans Activity | The following table summarizes information related to PSUs. 2018 2017 Number of Units Beginning of year 1,350,960 931,951 Granted 668,995 711,749 Notional dividends reinvested 66,280 44,893 Paid out (280,993 ) (239,509 ) Cancelled/forfeited (42,471 ) (16,910 ) Transferred to RSU Plan — (81,214 ) End of year 1,762,771 1,350,960 Additional Information (in millions) Compensation expense recognized $ 22 $ 26 Compensation expense unrecognized (1) 27 17 Cash payout (2) 14 11 Accrued liability as at December 31 (3) 50 41 Aggregate intrinsic value as at December 31 (4) 77 58 (1) Relates to unvested PSUs and is expected to be recognized over a weighted-average period of two years (2) Reflects a weighted-average payout price of $46.01 per PSU and a payout percentage of 109% ( 2017 - $ 41.46 and 113% , respectively) (3) Recognized at the respective December 31 st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 15 and 18 ) (4) Relates to outstanding PSUs and reflects a weighted-average contractual life of one year |
RSU Plans Activity | The following table summarizes information related to RSUs. 2018 2017 Number of Units Beginning of year 482,763 123,612 Granted 305,686 349,496 Notional dividends reinvested 26,263 15,407 Paid out (75,427 ) (74,876 ) Cancelled/forfeited (22,267 ) (12,090 ) Transferred from PSU plan — 81,214 End of year 717,018 482,763 Additional Information (in millions) Compensation expense recognized $ 11 $ 8 Compensation expense unrecognized (1) 15 11 Cash payout (2) 3 3 Accrued liability as at December 31 (3) 19 11 Aggregate intrinsic value as at December 31 (4) 34 22 (1) Relates to unvested RSUs and is expected to be recognized over a weighted-average period of two years (2) Reflects a weighted-average payout price of $45.55 per RSU ( 2017 - $ 43.42 ) (3) Recognized at the respective December 31 st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 15 and 18 ) (4) Relates to outstanding RSUs and reflects a weighted-average contractual life of one year |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Schedule of Other Income Net | (in millions) 2018 2017 Equity component of AFUDC $ 64 $ 74 Interest income 15 14 Equity (loss) income - BEL (1 ) 4 Net periodic pension cost (1 ) (11 ) Net foreign exchange gain (1) — 26 Other (17 ) 9 $ 60 $ 116 (1) Includes a one-time $21 million unrealized foreign exchange gain on US dollar-denominated affiliate loan in 2017 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Deferred Income Tax Assets and Liabilities | The significant components of deferred income tax assets and liabilities consist of the following. (in millions) 2018 2017 Gross deferred income tax assets Regulatory liabilities $ 635 $ 596 Tax loss and credit carryforwards 522 571 Employee future benefits 153 143 Unrealized foreign exchange losses on long-term debt 69 28 Other 76 51 1,455 1,389 Valuation allowance (56 ) (44 ) Net deferred income tax asset $ 1,399 $ 1,345 Gross deferred income tax liabilities PPE $ (3,780 ) $ (3,353 ) Regulatory assets (203 ) (203 ) Intangible assets (102 ) (87 ) (4,085 ) (3,643 ) Net deferred income tax liability $ (2,686 ) $ (2,298 ) |
Schedule of Unrecognized Tax Benefits | Unrecognized Tax Benefits (in millions) 2018 2017 Beginning of year $ 28 $ 23 Additions related to the current year 6 13 Adjustments related to prior years and U.S. Tax Reform 4 (8 ) End of year $ 38 $ 28 |
Schedule of Components of Income Tax Expense | Income Tax Expense (in millions) 2018 2017 Canadian Earnings before income tax expense $ 376 $ 461 Current income tax 51 41 Deferred income tax (25 ) 16 Total Canadian $ 26 $ 57 Foreign Earnings before income tax expense $ 1,075 $ 1,252 Current income tax (22 ) 3 Deferred income tax 161 528 Total Foreign $ 139 $ 531 Income tax expense $ 165 $ 588 |
Schedule of Effective Income Tax Rate Reconciliation | The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes. (in millions, except %) 2018 2017 Earnings before income tax expense $ 1,451 $ 1,713 Combined Canadian federal and provincial statutory income tax rate 28.5 % 28.0 % Expected federal and provincial taxes at statutory rate $ 414 $ 480 Increase (decrease) resulting from: Enactment of U.S. Tax Reform (1) — 168 Foreign and other statutory rate differentials (110 ) 31 Remeasurement of deferred tax liabilities (44 ) — AFUDC (14 ) (26 ) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (34 ) (26 ) Items capitalized for accounting purposes but expensed for income tax purposes (21 ) (21 ) Other (26 ) (18 ) Income tax expense $ 165 $ 588 Effective tax rate 11.4 % 34.3 % (1) In 2017 the Tax Cuts and Jobs Act implemented significant changes to U.S. tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21%, effective January 1, 2018. The Corporation's U.S. utilities and holding companies were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment. The one-time remeasurement resulted in an unfavourable earnings impact of $168 million recognized in deferred income tax expense ( $146 million after non-controlling interest). |
Summary of Operating Loss Carryforwards | Income Tax Carryforwards (in millions) Expiring Year 2018 Canadian Capital loss n/a $ 59 Non-capital loss 2025-2038 387 Other tax credits 2026-2037 2 448 Unrecognized (15 ) 433 Foreign Federal and state net operating loss 2022-2038 2,130 Other tax credits 2021-2038 115 2,245 Total income tax carryforwards recognized as at December 31 $ 2,678 |
Summary of Tax Carryforward Amounts | Income Tax Carryforwards (in millions) Expiring Year 2018 Canadian Capital loss n/a $ 59 Non-capital loss 2025-2038 387 Other tax credits 2026-2037 2 448 Unrecognized (15 ) 433 Foreign Federal and state net operating loss 2022-2038 2,130 Other tax credits 2021-2038 115 2,245 Total income tax carryforwards recognized as at December 31 $ 2,678 |
Employee Future Benefits (Table
Employee Future Benefits (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Schedule of Allocation of Plan Assets | Allocation of Plan Assets as at December 31 2018 Target Allocation (weighted-average %) 2018 2017 Equities 46 45 47 Fixed income 47 47 46 Real estate 6 7 6 Cash and other 1 1 1 100 100 100 Fair value of plan assets as at December 31 (in millions) Level 1 (1) Level 2 (1) Level 3 (1) Total 2018 Equities $ 508 $ 885 $ — $ 1,393 Fixed income 144 1,338 — 1,482 Real estate — 14 190 204 Private equities — — 25 25 Cash and other 8 11 — 19 $ 660 $ 2,248 $ 215 $ 3,123 2017 Equities $ 522 $ 949 $ — $ 1,471 Fixed income 133 1,289 — 1,422 Real estate — 13 168 181 Private equities — — 22 22 Cash and other 8 14 — 22 $ 663 $ 2,265 $ 190 $ 3,118 (1) Refer to Note 28 for a description of the fair value hierarchy. |
Schedule of Level 3 Changes in Plan Assets | The following table reconciles the changes in the fair value of pension plan assets that have been measured using Level 3 inputs. (in millions) 2018 2017 Balance, beginning of year $ 190 $ 113 Return on plan assets 15 12 Foreign currency translation 3 (2 ) Purchases, sales and settlements 7 67 Balance, end of year $ 215 $ 190 |
Schedule of Amounts Recognized in Balance Sheet | Funded Status Defined Benefit OPEB Plans (in millions) 2018 2017 2018 2017 Change in benefit obligation (1) Balance, beginning of year $ 3,215 $ 3,037 $ 665 $ 676 Service costs 84 76 31 27 Employee contributions 16 16 2 2 Interest costs 114 115 23 25 Benefits paid (145 ) (133 ) (26 ) (22 ) Actuarial losses (gains) (217 ) 217 (69 ) (14 ) Past service credits/plan amendments (1 ) — (3 ) (3 ) Foreign currency translation 141 (113 ) 32 (26 ) Balance, end of year (2) $ 3,207 $ 3,215 $ 655 $ 665 Change in value of plan assets Balance, beginning of year $ 2,841 $ 2,646 $ 277 $ 252 Actual return on plan assets (93 ) 336 (13 ) 37 Benefits paid (137 ) (127 ) (26 ) (22 ) Employee contributions 16 16 2 2 Employer contributions 79 69 29 26 Foreign currency translation 124 (99 ) 24 (18 ) Balance, end of year $ 2,830 $ 2,841 $ 293 $ 277 Funded status $ (377 ) $ (374 ) $ (362 ) $ (388 ) Balance sheet presentation Long-term assets (Note 11) $ 26 $ 31 $ 1 $ 3 Current liabilities (Note 15) (12 ) (12 ) (13 ) (10 ) Long-term liabilities (Note 18) (391 ) (393 ) (350 ) (381 ) $ (377 ) $ (374 ) $ (362 ) $ (388 ) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,936 million as at December 31, 2018 ( December 31, 2017 - $2,940 million ). |
Schedule of Funded Status | Funded Status Defined Benefit OPEB Plans (in millions) 2018 2017 2018 2017 Change in benefit obligation (1) Balance, beginning of year $ 3,215 $ 3,037 $ 665 $ 676 Service costs 84 76 31 27 Employee contributions 16 16 2 2 Interest costs 114 115 23 25 Benefits paid (145 ) (133 ) (26 ) (22 ) Actuarial losses (gains) (217 ) 217 (69 ) (14 ) Past service credits/plan amendments (1 ) — (3 ) (3 ) Foreign currency translation 141 (113 ) 32 (26 ) Balance, end of year (2) $ 3,207 $ 3,215 $ 655 $ 665 Change in value of plan assets Balance, beginning of year $ 2,841 $ 2,646 $ 277 $ 252 Actual return on plan assets (93 ) 336 (13 ) 37 Benefits paid (137 ) (127 ) (26 ) (22 ) Employee contributions 16 16 2 2 Employer contributions 79 69 29 26 Foreign currency translation 124 (99 ) 24 (18 ) Balance, end of year $ 2,830 $ 2,841 $ 293 $ 277 Funded status $ (377 ) $ (374 ) $ (362 ) $ (388 ) Balance sheet presentation Long-term assets (Note 11) $ 26 $ 31 $ 1 $ 3 Current liabilities (Note 15) (12 ) (12 ) (13 ) (10 ) Long-term liabilities (Note 18) (391 ) (393 ) (350 ) (381 ) $ (377 ) $ (374 ) $ (362 ) $ (388 ) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,936 million as at December 31, 2018 ( December 31, 2017 - $2,940 million ). |
Schedule of Net Benefit Costs | Net Benefit Cost Defined Benefit OPEB Plans (in millions) 2018 2017 2018 2017 Service costs $ 84 $ 76 $ 31 $ 27 Interest costs 114 115 23 25 Expected return on plan assets (162 ) (151 ) (16 ) (14 ) Amortization of actuarial losses 48 45 — 2 Amortization of past service credits/plan amendments — — (10 ) (12 ) Regulatory adjustments (1 ) 2 6 4 Net benefit cost $ 83 $ 87 $ 34 $ 32 |
Schedule of Amounts Recognized in AOCI and Net Regulatory Assets | The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive income and shows their classification on the consolidated balance sheets. Defined Benefit Pension Plans OPEB Plans (in millions) 2018 2017 2018 2017 Unamortized net actuarial losses (gains) $ 19 $ 22 $ (2 ) $ — Unamortized past service costs 1 1 2 3 Income tax recovery (3 ) (5 ) (1 ) (1 ) Accumulated other comprehensive income (Note 21) $ 17 $ 18 $ (1 ) $ 2 Net actuarial losses (gains) $ 457 $ 443 $ (25 ) $ 17 Past service credits (10 ) (11 ) (16 ) (23 ) Other regulatory deferrals 15 10 27 27 $ 462 $ 442 $ (14 ) $ 21 Regulatory assets (Note 9) $ 462 $ 442 $ 23 $ 68 Regulatory liabilities (Note 9) — — (37 ) (47 ) Net regulatory assets $ 462 $ 442 $ (14 ) $ 21 |
Schedule of Amounts Recognized in OCI and Regulatory Assets | The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income. Defined Benefit Pension Plans OPEB Plans (in millions) 2018 2017 2018 2017 Current year net actuarial (gains) losses $ (3 ) $ 5 $ (2 ) $ (1 ) Past service (credits) costs/plan amendments — — (1 ) 2 Amortization of actuarial losses (1 ) (1 ) — — Foreign currency translation 1 (1 ) — — Income tax recovery 2 — — — Total recognized in comprehensive income $ (1 ) $ 3 $ (3 ) $ 1 Current year net actuarial losses (gains) $ 41 $ 24 $ (39 ) $ (35 ) Past service credits/plan amendments — — (3 ) (5 ) Amortization of actuarial losses (47 ) (44 ) — (1 ) Amortization of past service (costs) credits 1 — 11 12 Foreign currency translation 21 (17 ) (3 ) 2 Regulatory adjustments 4 (1 ) (1 ) (6 ) Total recognized in regulatory assets $ 20 $ (38 ) $ (35 ) $ (33 ) |
Schedule of Assumptions Used | Significant Assumptions Defined Benefit OPEB Plans (weighted-average %) 2018 2017 2018 2017 Discount rate during the year (1) 3.56 3.98 3.57 3.96 Discount rate as at December 31 4.07 3.58 4.13 3.59 Expected long-term rate of return on plan assets (2) 5.80 5.97 5.48 5.81 Rate of compensation increase 3.35 3.34 — — Health care cost trend increase as at December 31 (3) — — 4.61 4.71 (1) ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach. (2) Developed by management with assistance from external actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. (3) The projected 2019 weighted-average health care cost trend rate for OPEB plans is 6.35% and is assumed to decrease over the next 14 years to the weighted-average ultimate health care cost trend rate of 4.61% in 2032 and thereafter |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | The following table summarizes for 2018 the effects of changing the health care cost trend rate by 1%. (in millions) 1% increase 1% decrease Increase (decrease) in accumulated benefit obligation $ 85 $ (67 ) Increase (decrease) in service and interest costs 11 (8 ) |
Schedule of Expected Benefit Payments | Defined Benefit Expected Benefit Payments Pension Payments OPEB (year) (in millions) (in millions) 2019 $ 147 $ 26 2020 152 28 2021 157 30 2022 165 32 2023 170 33 2024-2028 946 185 |
Supplementary Cash Flow Infor_2
Supplementary Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | (in millions) 2018 2017 Cash paid for Interest $ 969 $ 927 Income taxes 73 69 Change in working capital Accounts receivable and other current assets $ (204 ) $ (74 ) Prepaid expenses 1 (3 ) Inventories (8 ) (6 ) Regulatory assets - current portion 16 39 Accounts payable and other current liabilities 99 119 Regulatory liabilities - current portion (6 ) (172 ) $ (102 ) $ (97 ) Non-cash investing and financing activities Accrued capital expenditures $ 328 $ 307 Common share dividends reinvested 272 253 Gila River generating station Unit 2 capital lease 223 — Contributions in aid of construction 14 35 Exercise of stock options into common shares 1 5 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments and Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Hierarchy | The following table presents the fair value of the assets and liabilities that are accounted for at fair value on a recurring basis. (in millions) Level 1 (1) Level 2 (1) Level 3 (1) Total As at December 31, 2018 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 33 $ 8 $ 41 Energy contracts not subject to regulatory deferral (2) — 13 3 16 Other investments (4) 155 — — 155 $ 155 $ 46 $ 11 $ 212 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ — $ (86 ) $ (3 ) $ (89 ) Energy contracts not subject to regulatory deferral (5) — (1 ) — (1 ) Foreign exchange contracts, interest rate and total return swaps (6) (8 ) (1 ) — (9 ) $ (8 ) $ (88 ) $ (3 ) $ (99 ) As at December 31, 2017 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 19 $ 2 $ 21 Energy contracts not subject to regulatory deferral (2) — 26 4 30 Foreign exchange contracts (6) 3 — — 3 Other investments (4) 78 — — 78 $ 81 $ 45 $ 6 $ 132 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ (1 ) $ (103 ) $ (2 ) $ (106 ) Energy contracts not subject to regulatory deferral (5) — — (1 ) (1 ) Interest rate and total return swaps (6) — (1 ) — (1 ) $ (1 ) $ (104 ) $ (3 ) $ (108 ) (1) Under the hierarchy, fair value is determined using: (i) level 1 - unadjusted quoted prices in active markets; (ii) level 2 - other pricing inputs directly or indirectly observable in the marketplace; and (iii) level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the fair value measurement. (2) Included in accounts receivable and other current assets or other assets (3) Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of long-term wholesale trading contracts and certain gas swap contracts. (4) Included in other assets (5) Included in accounts payable and other current liabilities or other liabilities (6) Included in accounts receivable and other current assets, accounts payable and other current liabilities or other liabilities |
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 | The following table reconciles changes in the fair value of level 3 net assets and liabilities. (in millions) 2018 2017 Balance, beginning of year $ 3 $ 2 Realized gains (losses) 14 (13 ) Settlements (9 ) 12 Transfers of assets out of level 3 — (2 ) Transfers of liabilities out of level 3 — 4 Balance, end of year $ 8 $ 3 |
Derivative Asset Contracts Under Master Netting Agreements and Collateral Positions | The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following table presents the potential offset of counterparty netting. Energy Contracts Gross Amount Recognized on Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/Posted Net Amount As at December 31, 2018 Derivative assets $ 57 $ 28 $ 16 $ 13 Derivative liabilities (90 ) (28 ) — (62 ) As at December 31, 2017 Derivative assets $ 51 $ 17 $ 7 $ 27 Derivative liabilities (107 ) (17 ) — (90 ) |
Derivative Liability Contracts Under Master Netting Agreements and Collateral Positions | The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following table presents the potential offset of counterparty netting. Energy Contracts Gross Amount Recognized on Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/Posted Net Amount As at December 31, 2018 Derivative assets $ 57 $ 28 $ 16 $ 13 Derivative liabilities (90 ) (28 ) — (62 ) As at December 31, 2017 Derivative assets $ 51 $ 17 $ 7 $ 27 Derivative liabilities (107 ) (17 ) — (90 ) |
Schedule of Volume of Derivative Activity | As at December 31, 2018 , the Corporation had various energy contracts that will settle on various dates through 2029. The volumes related to electricity and natural gas derivatives are outlined below. As at December 31 2018 2017 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 774 1,291 Electricity power purchase contracts (GWh) 651 761 Gas swap contracts (PJ) 203 216 Gas supply contract premiums (PJ) 266 219 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 1,440 2,387 Gas swap contracts (PJ) 37 36 (1) GWh means gigawatt hours and PJ means petajoules |
Variable Interest Entity (Table
Variable Interest Entity (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Variable Interest Entities | The Corporation's consolidated financial statements include the following with respect to the Waneta Partnership. (in millions) 2018 2017 Assets Cash and cash equivalents $ 15 $ 16 Accounts receivable and other current assets 15 14 PPE 674 688 Intangible assets 30 30 $ 734 $ 748 Liabilities Accounts payable and other current liabilities $ (6 ) $ (28 ) Other liabilities (67 ) (63 ) (73 ) (91 ) Net assets before partners' equity $ 661 $ 657 Revenue $ 94 $ 93 Expenses Operating expenses 18 17 Depreciation and amortization 18 18 Finance charges 4 4 40 39 Net earnings $ 54 $ 54 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Consolidated Commitments in the Next Five Years and Periods Thereafter | As at December 31, 2018 , consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term debt and capital lease and finance obligations separately disclosed in Notes 16 and 17 , respectively, were as follows. (in millions) Total Due within 1 year Due in year 2 Due in year 3 Due in year 4 Due in year 5 Due after Interest obligations on long-term debt $ 16,345 $ 994 $ 973 $ 950 $ 902 $ 870 $ 11,656 Power purchase obligations (1) 2,438 254 191 174 170 172 1,477 Renewable power purchase obligations (2) 1,699 110 110 109 109 108 1,153 Gas purchase obligations (3) 1,348 359 290 242 202 144 111 Long-term contracts - UNS Energy (4) 777 176 142 92 60 46 261 ITC easement agreement (5) 436 14 14 14 14 14 366 Renewable energy credit purchase agreements (6) 146 24 26 18 11 11 56 Debt collection agreement (7) 119 3 3 3 3 3 104 Purchase of Springerville Common Facilities (8) 93 — — 93 — — — Joint-use asset and shared service agreements 52 3 3 3 3 3 37 Operating lease obligations 51 8 6 5 4 4 24 Other (9) 530 108 84 89 38 36 175 Total $ 24,034 $ 2,053 $ 1,842 $ 1,792 $ 1,516 $ 1,411 $ 15,420 (1) The most significant power purchase obligations are described below. Maritime Electric ( $771 million ): includes an agreement entitling Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and requiring Maritime Electric to pay its share of the station's capital operating costs for the life of the unit. Maritime Electric also has two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2024. FortisOntario ( $705 million ) : an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually from January 2020 through December 2030. FortisBC Energy ( $522 million ): an agreement with BC Hydro for the supply of electricity to the Tilbury liquefied natural gas facility expansion. FortisBC Electric ($ 345 million ) : includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20 -year term beginning October 1, 2013. (2) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require them to purchase 100% of the output of certain renewable energy generating facilities once commercial operation is achieved. Amounts shown are the estimated future payments. (3) Certain of the Corporation's subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2018 . (4) UNS Energy enters into long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas transportation services to meet load requirements, and the purchase of transmission services for purchased power. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates between 2019 and 2040. (5) ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licences associated with the land over which its transmission lines cross. The agreement expires in December 2050, subject to 10 potential 50 -year renewals thereafter. (6) UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations or other renewable generators. Payments are primarily made at contractually agreed-upon intervals based on metered energy production. (7) Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick transmission system interconnection. Payments under the agreement, which expires in February 2056, will be collected from customers in future rates. (8) UNS Energy is obligated to purchase an undivided 32.2% interest in the Springerville Common Facilities if the related two leases are not renewed. The initial lease terms expire in January 2021 (Note 17) . (9) Includes stock-based compensation plan obligations, land easements, asset retirement obligations, and defined benefit pension plan funding obligations. |
Description of Business - Regul
Description of Business - Regulated Utilities (Details) | Jan. 31, 2019 | Dec. 31, 2018communitycompanystationMW |
TEP and UNS Electric, Inc | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 3,377 | |
TEP and UNS Electric, Inc | Solar | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 57 | |
Central Hudson | Gas-Fired and Hydroelectric Power Generation | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 64 | |
FortisBC Energy | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of communities (more than) | community | 135 | |
FortisBC Electric | Hydroelectric Power Generation | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 225 | |
Generating facilities | station | 4 | |
Generating facilities, operating, maintenance and management services | station | 4 | |
Waneta Partnership | Hydroelectric Power Generation | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 335 | |
Newfoundland Power Inc. | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 139 | |
Newfoundland Power Inc. | Hydroelectric Power Generation | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 97 | |
Maritime Electric | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 145 | |
FortisOntario | Electric Utilities | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of utilities | company | 3 | |
Caribbean Utilities | Diesel | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 161 | |
Fortis Turks and Caicos | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of utilities | company | 2 | |
Fortis Turks and Caicos | Diesel | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 91 | |
Wataynikaneyap Partnership | ||
Public Utilities, General Disclosures [Line Items] | ||
Equity investment ownership (percent) | 49.00% | |
Wataynikaneyap Partnership | Subsequent event | ||
Public Utilities, General Disclosures [Line Items] | ||
Equity investment ownership (percent) | 39.00% | |
Wataynikaneyap Partnership | Fortis Inc. | ||
Public Utilities, General Disclosures [Line Items] | ||
Partnership with First Nation communities, number | community | 24 | |
Belize Electricity | ||
Public Utilities, General Disclosures [Line Items] | ||
Equity investment ownership (percent) | 33.00% | |
ITC | ||
Public Utilities, General Disclosures [Line Items] | ||
Controlling ownership interest (percent) | 80.10% | |
Noncontrolling ownership (percent) | 19.90% | |
Waneta Partnership | ||
Public Utilities, General Disclosures [Line Items] | ||
Controlling ownership interest (percent) | 51.00% | |
Noncontrolling ownership (percent) | 49.00% | |
Caribbean Utilities | ||
Public Utilities, General Disclosures [Line Items] | ||
Controlling ownership interest (percent) | 60.00% |
Description of Business - Non-R
Description of Business - Non-Regulated (Details) | 12 Months Ended |
Dec. 31, 2018stationMWBcf | |
Waneta Expansion | |
Public Utilities, General Disclosures [Line Items] | |
Long-term contract for electric power, term | 40 years |
Waneta Expansion | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 335 |
BECOL | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Long-term contract for electric power, term | 50 years |
Generating facilities | station | 3 |
Generating capacity (MW) | 51 |
Aitken Creek | |
Public Utilities, General Disclosures [Line Items] | |
Controlling ownership interest (percent) | 93.80% |
Generating capacity (billion cubic feet) | Bcf | 77 |
Waneta Expansion | |
Public Utilities, General Disclosures [Line Items] | |
Controlling ownership interest (percent) | 51.00% |
Regulation - ITC (Details)
Regulation - ITC (Details) - ITC $ in Millions, $ in Millions | Apr. 20, 2018 | Apr. 19, 2018 | Aug. 31, 2016 | Nov. 30, 2018 | Sep. 30, 2016 | Jun. 30, 2016 | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | May 31, 2016complaintcomplaint_period | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) |
Public Utilities, General Disclosures [Line Items] | |||||||||||
Approved cost-based formula, annual true-up (period) | 2 years | ||||||||||
ROE refund liability, initial and second refund periods | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Number of complaint periods | complaint_period | 2 | ||||||||||
Complaint period | 15 months | ||||||||||
ROE refund liability, initial complaint | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Refunds, including interest | $ 118 | $ 158 | |||||||||
ROE refund liability, second refund period | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Estimated potential refund | $ 151 | $ 145 | $ 206 | $ 182 | |||||||
FERC | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Approved cost-based formula (years) | 1 year | ||||||||||
Approved cost-based formula, annual true-up (period) | 2 years | ||||||||||
ROE (percent) | 12.38% | 10.32% | |||||||||
Capital structure of common equity (percent) | 60.00% | 60.00% | |||||||||
Independence incentive adders included in transmission rates | 0.25% | 0.50% | 0.25% | ||||||||
Adder reduction percent | 0.25% | ||||||||||
Recommended ROE (percent) | 9.70% | ||||||||||
FERC | ROE refund liability, initial and second refund periods | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Complaints (number) | complaint | 2 | ||||||||||
FERC | Minimum | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
ROE (percent) | 11.07% | 11.32% | |||||||||
Independence incentive adders included in transmission rates | 0.50% | ||||||||||
FERC | Maximum | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
ROE (percent) | 11.35% | 12.16% | 12.16% | ||||||||
Independence incentive adders included in transmission rates | 1.00% | ||||||||||
Recommended ROE (percent) | 10.68% |
Regulation - UNS Energy (Detail
Regulation - UNS Energy (Details) - ACC | Feb. 27, 2017 | Aug. 01, 2016 | Jul. 01, 2013 | May 01, 2012 |
TEP | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 9.75% | 10.00% | ||
Capital structure of common equity (percent) | 50.00% | 43.50% | ||
UNS Electric | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 9.50% | |||
Capital structure of common equity (percent) | 52.80% | |||
UNS Gas | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 9.75% | |||
Capital structure of common equity (percent) | 50.80% |
Regulation - Central Hudson (De
Regulation - Central Hudson (Details) - Central Hudson | Jul. 01, 2018 | Jul. 01, 2015 |
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity and capital structure, term | 3 years | |
ROE (percent) | 8.80% | 9.00% |
Capital structure of common equity (percent) | 48.00% | |
Minimum | ||
Public Utilities, General Disclosures [Line Items] | ||
Earnings in excess of (basis points) | 0.50% | |
Maximum | ||
Public Utilities, General Disclosures [Line Items] | ||
Earnings in excess of (basis points) | 1.00% | |
Year one | ||
Public Utilities, General Disclosures [Line Items] | ||
Capital structure of common equity (percent) | 48.00% | |
Year two | ||
Public Utilities, General Disclosures [Line Items] | ||
Capital structure of common equity (percent) | 49.00% | |
Year three | ||
Public Utilities, General Disclosures [Line Items] | ||
Capital structure of common equity (percent) | 50.00% |
Regulation - FortisBC Energy an
Regulation - FortisBC Energy and FortisBC Electric (Details) | Jan. 01, 2016 | Dec. 31, 2018 |
FortisBC Energy and FortisBC Electric | ||
Public Utilities, General Disclosures [Line Items] | ||
Variance sharing (percent) | 50.00% | |
BCUC | FortisBC Energy and FortisBC Electric | ||
Public Utilities, General Disclosures [Line Items] | ||
Variance sharing (percent) | 50.00% | |
BCUC | FortisBC Energy | ||
Public Utilities, General Disclosures [Line Items] | ||
Fixed productivity adjustment (percent) | 1.10% | |
ROE (percent) | 8.75% | |
Capital structure of common equity (percent) | 38.50% | |
BCUC | FortisBC Electric | ||
Public Utilities, General Disclosures [Line Items] | ||
Fixed productivity adjustment (percent) | 1.03% | |
ROE (percent) | 9.15% | |
Capital structure of common equity (percent) | 40.00% |
Regulation - FortisAlberta (Det
Regulation - FortisAlberta (Details) - FortisAlberta - AUC | 12 Months Ended |
Dec. 31, 2018 | |
Public Utilities, General Disclosures [Line Items] | |
Efficiency gains benefit period beyond initial term (period) | 2 years |
ROE (percent) | 8.50% |
Capital structure of common equity (percent) | 37.00% |
Regulation - Other Electric (De
Regulation - Other Electric (Details) | Mar. 01, 2016 | Dec. 31, 2018companylicense | Dec. 31, 2017 | Dec. 31, 2018company |
Newfoundland Power Inc. | PUB | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 8.50% | |||
Capital structure of common equity (percent) | 45.00% | |||
Maritime Electric | IRAC | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 9.35% | |||
Capital structure of common equity (percent) | 40.00% | |||
ROE rate term | 3 years | |||
FortisOntario | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Franchise agreement term | 35 years | |||
FortisOntario | Electric Utilities | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of utilities | 3 | 3 | ||
PBR term | 5 years | |||
FortisOntario | Electric Utilities, future test year to establish rates | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of utilities | 2 | 2 | ||
FortisOntario | OEB | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Capital structure of common equity (percent) | 40.00% | |||
FortisOntario | OEB | Minimum | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 8.78% | 8.78% | ||
FortisOntario | OEB | Maximum | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROE (percent) | 9.30% | 9.30% | ||
FortisOntario | OEB | Electric Utilities | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of utilities | 3 | 3 | ||
Caribbean Utilities | Government of the Cayman Islands | ||||
Public Utilities, General Disclosures [Line Items] | ||||
T & D license term | 20 years | |||
Generation license term | 25 years | |||
Caribbean Utilities | Government of the Cayman Islands | Minimum | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROA (percent) | 7.00% | 6.75% | ||
Caribbean Utilities | Government of the Cayman Islands | Maximum | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROA (percent) | 9.00% | 8.75% | ||
Fortis Turks and Caicos | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of utilities | 2 | 2 | ||
Fortis Turks and Caicos | Government of the Turks and Caicos Islands | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Licenses (number) | license | 2 | |||
Operating license term | 50 years | |||
Fortis Turks and Caicos | Government of the Turks and Caicos Islands | Minimum | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROA (percent) | 15.00% | |||
Fortis Turks and Caicos | Government of the Turks and Caicos Islands | Maximum | ||||
Public Utilities, General Disclosures [Line Items] | ||||
ROA (percent) | 17.50% |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Regulated Operations [Abstract] | ||
Debt component of AFUDC | $ 31 | $ 38 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, composite depreciation rate | 2.50% | 2.60% |
Property, plant and equipment, generation remaining useful life | 24 years | 28 years |
Property, plant and equipment, other remaining useful life | 15 years | 14 years |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution remaining useful life | 33 years | 33 years |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution remaining useful life | 35 years | 34 years |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission remaining useful life | 42 years | 41 years |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission remaining useful life | 41 years | 34 years |
Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 0.90% | 0.90% |
Property, plant and equipment, generation useful life | 5 years | 5 years |
Property, plant and equipment, other useful life | 3 years | 3 years |
Minimum | Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 5 years | 5 years |
Minimum | Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 14 years | 14 years |
Minimum | Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 20 years | 20 years |
Minimum | Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 5 years | 5 years |
Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 34.60% | 34.60% |
Property, plant and equipment, generation useful life | 85 years | 85 years |
Property, plant and equipment, other useful life | 70 years | 70 years |
Maximum | Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 80 years | 80 years |
Maximum | Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 95 years | 95 years |
Maximum | Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 90 years | 80 years |
Maximum | Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 85 years | 80 years |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Intangible Assets (Details) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 4 years | 4 years |
Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 57 years | 57 years |
Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 13 years | 10 years |
Minimum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible asset amortization rate | 1.00% | 1.00% |
Minimum | Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 3 years | 3 years |
Minimum | Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 36 years | 36 years |
Minimum | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 10 years | 10 years |
Maximum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible asset amortization rate | 50.00% | 50.00% |
Maximum | Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 10 years | 10 years |
Maximum | Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 90 years | 80 years |
Maximum | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 100 years | 100 years |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Goodwill (Details) | 12 Months Ended |
Dec. 31, 2018reporting_unit | |
Accounting Policies [Abstract] | |
Number of reporting units | 11 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Employee Future Benefits and Stock-Based Compensation (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accounting Policies [Abstract] | ||
Defined benefit plan, market-related value of plan assets recognition period | 3 years | |
Options | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 4 years | |
Exercise price, VWAP (period) | 5 days | |
DSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Exercise price, VWAP (period) | 5 days | |
DSUs | Director | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Volume weighted average price, share price (in dollars per share) | $ 45.14 | $ 46.01 |
PSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Exercise price, VWAP (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | $ 45.14 | 46.01 |
RSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Exercise price, VWAP (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | $ 45.14 | $ 46.01 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Foreign Currency Translation (Details) - $ / $ | Dec. 31, 2018 | Dec. 31, 2017 |
Schedule of Equity Method Investments [Line Items] | ||
Foreign exchange rate (CAD per USD) | 1.36 | 1.25 |
Weighted Average | ||
Schedule of Equity Method Investments [Line Items] | ||
Foreign exchange rate (CAD per USD) | 1.30 | 1.30 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Income Taxes (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Variable Interest Entity [Line Items] | ||
Undistributed earnings on foreign subsidiaries | $ 2,300 | $ 561 |
Hydroelectric Power Generation | BECOL | ||
Variable Interest Entity [Line Items] | ||
Long-term contract for electric power, term | 50 years |
Summary of Significant Accou_10
Summary of Significant Accounting Policies - New Accounting Policies (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Operating Expenses | $ (2,287,000,000) | $ (2,250,000,000) |
ASU No. 2017-07 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Operating Expenses | 11,000,000 | |
Other Income, Net | $ 0 | |
Difference between revenue guidance in effect before and after Topic 606 | ASC 606 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Decrease revenue | $ 49,000,000 |
Future Accounting Pronounceme_2
Future Accounting Pronouncements (Details) - ASU No. 2016-02 - Forecast $ in Millions | Jan. 01, 2019CAD ($) |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Right-of-use assets | $ 50 |
Lease liabilities | $ 50 |
Segmented Information - Related
Segmented Information - Related-party and Inter-Company Transactions (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Belize Electricity | Equity Method Investee | ||
Related Party Transaction [Line Items] | ||
Due from related party | $ 16 | $ 20 |
Waneta Partnership | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | 47 | 46 |
Aitken Creek | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | $ 25 | $ 24 |
Segmented Information - Informa
Segmented Information - Information by Reportable Segment (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||
Revenue | $ 8,390 | $ 8,301 | |
Energy supply costs | 2,495 | 2,361 | |
Operating expenses | 2,287 | 2,250 | |
Depreciation and amortization | 1,243 | 1,179 | |
Operating income | 2,365 | 2,511 | |
Other income, net (Note 23) | 60 | 116 | |
Finance charges | 974 | 914 | |
Income tax expense | 165 | 588 | |
Net earnings | 1,286 | 1,125 | |
Non-controlling interests | 120 | 97 | |
Preference share dividends | 66 | 65 | |
Common equity shareholders | 1,100 | 963 | |
Goodwill | 12,530 | 11,644 | $ 12,364 |
Total assets | 53,051 | 47,822 | |
Capital expenditures | 3,218 | 3,024 | |
Inter-segment eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenue | (10) | (12) | |
Energy supply costs | 0 | (1) | |
Operating expenses | (10) | (11) | |
Depreciation and amortization | 0 | 0 | |
Operating income | 0 | 0 | |
Other income, net (Note 23) | 0 | (1) | |
Finance charges | 0 | (1) | |
Income tax expense | 0 | 0 | |
Net earnings | 0 | 0 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 0 | 0 | |
Goodwill | 0 | 0 | |
Total assets | (73) | (107) | |
Capital expenditures | 0 | 0 | |
REGULATED | Operating segments | |||
Segment Reporting Information [Line Items] | |||
Revenue | 8,216 | 8,086 | |
Energy supply costs | 2,493 | 2,360 | |
Operating expenses | 2,229 | 2,200 | |
Depreciation and amortization | 1,209 | 1,145 | |
Operating income | 2,285 | 2,381 | |
Other income, net (Note 23) | 69 | 88 | |
Finance charges | 780 | 721 | |
Income tax expense | 317 | 638 | |
Net earnings | 1,257 | 1,110 | |
Non-controlling interests | 93 | 71 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 1,164 | 1,039 | |
Goodwill | 12,503 | 11,617 | |
Total assets | 51,519 | 46,248 | |
Capital expenditures | 3,167 | 3,003 | |
REGULATED | Operating segments | ITC | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,504 | 1,575 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 448 | 433 | |
Depreciation and amortization | 234 | 220 | |
Operating income | 822 | 922 | |
Other income, net (Note 23) | 40 | 37 | |
Finance charges | 285 | 259 | |
Income tax expense | 139 | 371 | |
Net earnings | 438 | 329 | |
Non-controlling interests | 77 | 57 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 361 | 272 | |
Goodwill | 8,369 | 7,698 | |
Total assets | 19,798 | 17,581 | |
Capital expenditures | 998 | 982 | |
REGULATED | Operating segments | UNS Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 2,202 | 2,080 | |
Energy supply costs | 868 | 711 | |
Operating expenses | 609 | 609 | |
Depreciation and amortization | 272 | 260 | |
Operating income | 453 | 500 | |
Other income, net (Note 23) | 10 | 19 | |
Finance charges | 104 | 101 | |
Income tax expense | 66 | 148 | |
Net earnings | 293 | 270 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 293 | 270 | |
Goodwill | 1,884 | 1,733 | |
Total assets | 10,182 | 8,596 | |
Capital expenditures | 599 | 534 | |
REGULATED | Operating segments | Central Hudson | |||
Segment Reporting Information [Line Items] | |||
Revenue | 924 | 872 | |
Energy supply costs | 315 | 260 | |
Operating expenses | 410 | 399 | |
Depreciation and amortization | 71 | 65 | |
Operating income | 128 | 148 | |
Other income, net (Note 23) | 7 | 5 | |
Finance charges | 41 | 41 | |
Income tax expense | 20 | 42 | |
Net earnings | 74 | 70 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 74 | 70 | |
Goodwill | 615 | 566 | |
Total assets | 3,670 | 3,188 | |
Capital expenditures | 245 | 220 | |
REGULATED | Operating segments | FortisBC Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,187 | 1,198 | |
Energy supply costs | 322 | 411 | |
Operating expenses | 308 | 300 | |
Depreciation and amortization | 219 | 198 | |
Operating income | 338 | 289 | |
Other income, net (Note 23) | 7 | 22 | |
Finance charges | 134 | 116 | |
Income tax expense | 55 | 40 | |
Net earnings | 156 | 155 | |
Non-controlling interests | 1 | 1 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 155 | 154 | |
Goodwill | 913 | 913 | |
Total assets | 6,815 | 6,418 | |
Capital expenditures | 486 | 446 | |
REGULATED | Operating segments | FortisAlberta | |||
Segment Reporting Information [Line Items] | |||
Revenue | 579 | 600 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 167 | 198 | |
Depreciation and amortization | 192 | 190 | |
Operating income | 220 | 212 | |
Other income, net (Note 23) | 1 | 2 | |
Finance charges | 100 | 93 | |
Income tax expense | 1 | 1 | |
Net earnings | 120 | 120 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 120 | 120 | |
Goodwill | 227 | 227 | |
Total assets | 4,691 | 4,454 | |
Capital expenditures | 433 | 414 | |
REGULATED | Operating segments | FortisBC Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 408 | 398 | |
Energy supply costs | 135 | 142 | |
Operating expenses | 105 | 90 | |
Depreciation and amortization | 61 | 62 | |
Operating income | 107 | 104 | |
Other income, net (Note 23) | 3 | 2 | |
Finance charges | 40 | 37 | |
Income tax expense | 14 | 14 | |
Net earnings | 56 | 55 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 56 | 55 | |
Goodwill | 235 | 235 | |
Total assets | 2,244 | 2,197 | |
Capital expenditures | 106 | 105 | |
REGULATED | Operating segments | Other Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,412 | 1,363 | |
Energy supply costs | 853 | 836 | |
Operating expenses | 182 | 171 | |
Depreciation and amortization | 160 | 150 | |
Operating income | 217 | 206 | |
Other income, net (Note 23) | 1 | 1 | |
Finance charges | 76 | 74 | |
Income tax expense | 22 | 22 | |
Net earnings | 120 | 111 | |
Non-controlling interests | 15 | 13 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 105 | 98 | |
Goodwill | 260 | 245 | |
Total assets | 4,119 | 3,814 | |
Capital expenditures | 300 | 302 | |
NON-REGULATED | Operating segments | Energy Infra-structure | |||
Segment Reporting Information [Line Items] | |||
Revenue | 184 | 226 | |
Energy supply costs | 2 | 2 | |
Operating expenses | 40 | 49 | |
Depreciation and amortization | 32 | 32 | |
Operating income | 110 | 143 | |
Other income, net (Note 23) | 1 | 1 | |
Finance charges | 6 | 5 | |
Income tax expense | 6 | 19 | |
Net earnings | 99 | 120 | |
Non-controlling interests | 27 | 26 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 72 | 94 | |
Goodwill | 27 | 27 | |
Total assets | 1,478 | 1,605 | |
Capital expenditures | 44 | 21 | |
NON-REGULATED | Operating segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Revenue | 0 | 1 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 28 | 12 | |
Depreciation and amortization | 2 | 2 | |
Operating income | (30) | (13) | |
Other income, net (Note 23) | (10) | 28 | |
Finance charges | 188 | 189 | |
Income tax expense | (158) | (69) | |
Net earnings | (70) | (105) | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 66 | 65 | |
Common equity shareholders | (136) | (170) | |
Goodwill | 0 | 0 | |
Total assets | 127 | 76 | |
Capital expenditures | $ 7 | $ 0 |
Revenue - Schedule of Revenue (
Revenue - Schedule of Revenue (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 8,326 | $ 8,198 |
Alternative revenue | 16 | (46) |
Other revenue | 48 | 149 |
Revenues | 8,390 | 8,301 |
Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 7,918 | 7,803 |
Other services revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 408 | 395 |
Other services revenue | Regulated Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 234 | 217 |
ITC | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,539 | 1,583 |
UNS Energy | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,993 | 1,875 |
Central Hudson | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 963 | 814 |
FortisBC Energy | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,136 | 1,244 |
FortisAlberta | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 554 | 593 |
FortisBC Electric | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 354 | 347 |
Newfoundland Power | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 651 | 666 |
Maritime Electric | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 200 | 191 |
FortisOntario | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 197 | 197 |
Caribbean Utilities | Caribbean | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 253 | 222 |
FortisTCI | Caribbean | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 78 | $ 71 |
Revenue - Narrative (Details)
Revenue - Narrative (Details) | 12 Months Ended |
Dec. 31, 2018 | |
ITC | |
Disaggregation of Revenue [Line Items] | |
True-up period | 2 years |
UNS Energy | |
Disaggregation of Revenue [Line Items] | |
Year over year recovery cap | 1.00% |
FortisBC Energy and FortisBC Electric | |
Disaggregation of Revenue [Line Items] | |
Earnings in excess of (basis points) | 50.00% |
Refund or recovery period | 2 years |
Accounts Receivable and Other_3
Accounts Receivable and Other Current Assets - Schedule of Accounts Receivable and Other Current Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Receivables [Abstract] | ||
Trade accounts receivable | $ 538 | $ 460 |
Unbilled accounts receivable | 575 | 562 |
Allowance for doubtful accounts | (33) | (31) |
Total accounts receivable | 1,080 | 991 |
Income tax receivable | 91 | 8 |
Other | 186 | 132 |
Accounts receivable and other current assets | $ 1,357 | $ 1,131 |
Inventories (Details)
Inventories (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 398 | $ 367 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 280 | 238 |
Gas and fuel in storage | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 87 | 97 |
Coal inventory | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 31 | $ 32 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 3,178 | $ 3,045 |
Less: Current portion | (324) | (303) |
Long-term regulatory assets | 2,854 | 2,742 |
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 3,626 | 3,446 |
Less: Current portion | (656) | (490) |
Long-term regulatory liabilities | 2,970 | 2,956 |
Deferred income taxes (Notes 3 and 24) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,574 | 1,484 |
Asset removal cost provision (Note 3) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,169 | 1,095 |
Rate stabilization and related accounts (v) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 220 | 254 |
ROE complaints liability (Note 2) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 206 | 182 |
Energy efficiency liability (vii) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 106 | 82 |
Renewable energy surcharge (viii) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 85 | 66 |
Electric and gas moderator account (ix) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 60 | 58 |
Employee future benefits (Notes 3 and 25) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 37 | 47 |
Other (vii) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 169 | 178 |
Deferred income taxes (Notes 3 and 24) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,532 | 1,403 |
Employee future benefits (Notes 3 and 25) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 485 | 510 |
Deferred energy management costs (i) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 230 | 200 |
Deferred energy management costs (i) | Minimum | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period | 1 year | |
Deferred energy management costs (i) | Maximum | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period | 10 years | |
Deferred lease costs (ii) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 110 | 104 |
Deferred operating overhead costs (iii) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 103 | 91 |
Generation early retirement costs (iv) | UNS Energy | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 98 | 105 |
Rate stabilization and related accounts (v) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 90 | 95 |
Manufactured gas plant site remediation deferral (Note 18) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 73 | 75 |
Derivatives (Notes 3 and 28) | Energy contracts subject to regulatory deferral | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 57 | 87 |
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 9 | 2 |
Other (vii) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 400 | $ 375 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities - Narrative Assets (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Regulatory Assets [Line Items] | ||
Threshold amount | $ 40,000,000 | |
Regulatory assets | 3,178,000,000 | $ 3,045,000,000 |
Deferred energy management costs (i) | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 230,000,000 | 200,000,000 |
Deferred energy management costs (i) | Minimum | ||
Regulatory Assets [Line Items] | ||
Regulatory asset, amortization period | 1 year | |
Deferred energy management costs (i) | Maximum | ||
Regulatory Assets [Line Items] | ||
Regulatory asset, amortization period | 10 years | |
Regulatory assets not earning a return | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 1,490,000,000 | $ 1,464,000,000 |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities - Narrative Liabilities (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($) | |
Individually less than | |
Regulatory Liabilities [Line Items] | |
Threshold amount | $ 40 |
Renewable energy surcharge (viii) | UNS Energy | |
Regulatory Liabilities [Line Items] | |
Renewable energy target (at least) (percent) | 15.00% |
Electric and gas moderator account (ix) | Central Hudson | |
Regulatory Liabilities [Line Items] | |
Approved rate (period) | 3 years |
Assets Held for Sale - Narrativ
Assets Held for Sale - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Jan. 31, 2019 | Dec. 31, 2016 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Equity | $ 18,456 | $ 16,749 | $ 16,450 | |
Earnings before income tax expense | $ 54 | $ 54 | ||
Attributable to common equity shareholders | 51.00% | 51.00% | ||
Non-Controlling Interests | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Equity | $ 1,923 | $ 1,746 | $ 1,853 | |
Non-Controlling Interests | Assets held for sale | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Equity | $ 324 | |||
Waneta Expansion | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Controlling ownership interest (percent) | 51.00% | |||
Noncontrolling ownership (percent) | 49.00% | |||
Waneta Expansion | Subsequent event | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Sales consideration | $ 1,000 |
Assets Held for Sale - Schedule
Assets Held for Sale - Schedule of Asset Held for Sale (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Discontinued Operations and Disposal Groups [Abstract] | ||
Cash | $ 15 | $ 0 |
Accounts receivable and other current assets | 3 | |
PPE | 718 | |
Intangible assets | 30 | |
Total assets held for sale | 766 | 0 |
Accounts payable and other current liabilities | 2 | |
Other liabilities | 67 | |
Total liabilities associated with assets held for sale | $ 69 | $ 0 |
Other Assets - Schedule of Othe
Other Assets - Schedule of Other Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Renewable Energy Credits (Note 9 (viii)) | $ 88 | $ 62 |
Other investments | 34 | 29 |
Deferred compensation plan | 26 | 24 |
Other | 116 | 109 |
Other assets | 552 | 480 |
BEL | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Equity investment | 76 | 73 |
Wataynikaneyap Partnership | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Equity investment | 43 | 22 |
Supplemental Executive Retirement Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Plan assets, noncurrent | 143 | 130 |
Defined Benefit Pension Plans | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Plan assets, noncurrent | $ 26 | $ 31 |
Other Assets - Narrative (Detai
Other Assets - Narrative (Details) - Supplemental Executive Retirement Plan - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Schedule of Investments [Line Items] | ||
Plan assets, noncurrent | $ 143 | $ 130 |
ITC | ||
Schedule of Investments [Line Items] | ||
Plan assets, noncurrent | $ 72 | $ 66 |
Property, Plant And Equipment -
Property, Plant And Equipment - Schedule of Utility Capital Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | $ 44,355 | $ 40,249 |
Accumulated Depreciation | (11,701) | (10,581) |
Net Book Value | 32,654 | 29,668 |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 10,880 | 9,963 |
Accumulated Depreciation | (3,076) | (2,864) |
Net Book Value | 7,804 | 7,099 |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 4,767 | 4,093 |
Accumulated Depreciation | (1,244) | (1,157) |
Net Book Value | 3,523 | 2,936 |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 14,665 | 12,571 |
Accumulated Depreciation | (3,212) | (2,838) |
Net Book Value | 11,453 | 9,733 |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 2,214 | 1,954 |
Accumulated Depreciation | (639) | (596) |
Net Book Value | 1,575 | 1,358 |
Generation | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 6,164 | 6,079 |
Accumulated Depreciation | (2,279) | (1,996) |
Net Book Value | 3,885 | 4,083 |
Other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 3,877 | 3,608 |
Accumulated Depreciation | (1,251) | (1,130) |
Net Book Value | 2,626 | 2,478 |
Assets under construction | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 1,478 | 1,717 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | 1,478 | 1,717 |
Land | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 310 | 264 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | $ 310 | $ 264 |
Property, Plant And Equipment_2
Property, Plant And Equipment - Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)kPakV | Dec. 31, 2017CAD ($) | |
Regulated Operations [Abstract] | ||
Electric distribution capacity (kV) | kV | 69 | |
Gas distribution capacity (kPa) | kPa | 2,070 | |
Gas distribution capacity, hoop stress (percent) | 20.00% | |
Electric transmission capacity (kV) | kV | 69 | |
Gas transmission capacity, and higher (kPa) | kPa | 2,070 | |
Gas transmission capacity, hoop stress (percent) | 20.00% | |
Capital assets under capital lease | $ | $ 656 | $ 423 |
Capital assets under capital lease accumulated depreciation | $ | $ 203 | $ 176 |
Property, Plant And Equipment_3
Property, Plant And Equipment - Schedule of Jointly-Owned Utility Plants (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Jointly Owned Facilities [Line Items] | |
Cost | $ 2,062 |
Accumulated Depreciation | (822) |
Net Book Value | $ 1,240 |
San Juan Unit 1 | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 50.00% |
Cost | $ 397 |
Accumulated Depreciation | (183) |
Net Book Value | $ 214 |
Four Corners Units 4 and 5 | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 7.00% |
Cost | $ 239 |
Accumulated Depreciation | (104) |
Net Book Value | $ 135 |
Luna Energy Facility | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 33.30% |
Cost | $ 79 |
Accumulated Depreciation | (5) |
Net Book Value | $ 74 |
Gila River Common Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 25.00% |
Cost | $ 45 |
Accumulated Depreciation | (16) |
Net Book Value | $ 29 |
Springerville Coal Handling Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 83.00% |
Cost | $ 284 |
Accumulated Depreciation | (117) |
Net Book Value | 167 |
Transmission Facilities | |
Jointly Owned Facilities [Line Items] | |
Cost | 1,018 |
Accumulated Depreciation | (397) |
Net Book Value | $ 621 |
Transmission Facilities | Minimum | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 1.00% |
Transmission Facilities | Maximum | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 80.00% |
Intangible Assets - Schedule of
Intangible Assets - Schedule of Intangible Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | $ 1,916 | $ 1,707 |
Accumulated Amortization | (716) | (626) |
Net Book Value | 1,200 | 1,081 |
Land, transmission and water rights | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 855 | 743 |
Accumulated Amortization | (125) | (103) |
Net Book Value | 730 | 640 |
Assets under construction | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 81 | 63 |
Accumulated Amortization | 0 | 0 |
Net Book Value | 81 | 63 |
Computer software | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 860 | 784 |
Accumulated Amortization | (533) | (474) |
Net Book Value | 327 | 310 |
Other | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 120 | 117 |
Accumulated Amortization | (58) | (49) |
Net Book Value | $ 62 | $ 68 |
Intangible Assets - Narrative (
Intangible Assets - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Amortization - intangible assets | $ 106 | $ 97 |
Amortization expense, next twelve months | 81 | |
Amortization expense, year two | 81 | |
Amortization expense, year three | 81 | |
Amortization expense, year four | 81 | |
Amortization expense, year five | 81 | |
Land, transmission and water rights | ||
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Cost not subject to amortization | $ 131 | $ 150 |
Goodwill (Details)
Goodwill (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Goodwill [Roll Forward] | ||
Balance, beginning of year | $ 11,644,000,000 | $ 12,364,000,000 |
Foreign currency translation impacts | 886,000,000 | (714,000,000) |
Balance, end of year | 12,530,000,000 | 11,644,000,000 |
Goodwill impairment loss | 0 | 0 |
ITC | ||
Goodwill [Roll Forward] | ||
Acquisition of ITC | $ 0 | $ (6,000,000) |
Accounts Payable and Other Cu_3
Accounts Payable and Other Current Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Payables and Accruals [Abstract] | ||
Trade accounts payable | $ 679 | $ 696 |
Gas and fuel cost payable | 281 | 146 |
Customer and other deposits | 267 | 204 |
Interest payable | 230 | 223 |
Accrued taxes other than income taxes | 206 | 178 |
Dividends payable | 199 | 185 |
Employee compensation and benefits payable | 193 | 184 |
Fair value of derivatives (Note 28) | 69 | 71 |
Manufactured gas plant site remediation (Note 18) | 32 | 35 |
Defined benefit pension and OPEB liabilities (Note 25) | 25 | 22 |
Other | 108 | 109 |
Accounts payable and other current liabilities | $ 2,289 | $ 2,053 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Total long-term debt | $ 24,231 | $ 21,535 |
Less: Deferred financing costs and debt discounts | (146) | (139) |
Less: Current installments of long-term debt | (926) | (705) |
Long-term debt | 23,159 | 20,691 |
Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 1,066 | $ 671 |
Credit facility | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 3.30% | 2.50% |
Less: Current installments of long-term debt | $ (735) | $ (312) |
Credit facility | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | 1,066 | 671 |
ITC | ||
Debt Instrument [Line Items] | ||
Fair value adjustment - ITC acquisition | $ 161 | $ 167 |
ITC | Secured | Fixed Rate Secured US First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.51% | 4.67% |
Total long-term debt | $ 2,652 | $ 2,063 |
ITC | Secured | Fixed Rate Secured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.19% | 4.19% |
Total long-term debt | $ 648 | $ 596 |
ITC | Unsecured | Fixed Rate Unsecured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 3.91% | 3.91% |
Total long-term debt | $ 3,751 | $ 3,451 |
ITC | Unsecured | 6.00% Unsecured US Shareholder Note | ||
Debt Instrument [Line Items] | ||
Stated interest rate (percent) | 6.00% | 6.00% |
Total long-term debt | $ 271 | $ 250 |
ITC | Unsecured | Variable Rate Unsecured US Term Loan Credit Agreement | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 2.03% | 2.03% |
Total long-term debt | $ 0 | $ 63 |
UNS Energy | Unsecured | Fixed and Variable Rate Unsecured US Tax-Exempt Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.66% | 4.04% |
Total long-term debt | $ 654 | $ 773 |
UNS Energy | Unsecured | Fixed Rate Unsecured US Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.38% | 4.26% |
Total long-term debt | $ 1,943 | $ 1,411 |
Central Hudson | Unsecured | Fixed and Variable Rate Unsecured US Promissory Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.43% | 4.28% |
Total long-term debt | $ 938 | $ 770 |
FortisBC Energy | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 5.03% | 5.13% |
Total long-term debt | $ 2,595 | $ 2,395 |
FortisAlberta | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.64% | 4.70% |
Total long-term debt | $ 2,185 | $ 2,035 |
FortisBC Electric | Secured | Fixed Rate Secured Debentures | ||
Debt Instrument [Line Items] | ||
Stated interest rate (percent) | 8.80% | 8.80% |
Total long-term debt | $ 25 | $ 25 |
FortisBC Electric | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 5.05% | 5.05% |
Total long-term debt | $ 710 | $ 710 |
Other Electric | Secured | Fixed Rate Secured First Mortgage Sinking Fund Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 6.14% | 6.14% |
Total long-term debt | $ 578 | $ 585 |
Other Electric | Secured | Fixed Rate Secured First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 5.66% | 6.19% |
Total long-term debt | $ 220 | $ 195 |
Other Electric | Unsecured | Fixed Rate Unsecured Senior Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.45% | 6.11% |
Total long-term debt | $ 152 | $ 104 |
Other Electric | Unsecured | Fixed and Variable Rate Unsecured US Senior Loan Notes and Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.76% | 4.80% |
Total long-term debt | $ 584 | $ 525 |
Corporate and Other | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 335 | |
Corporate and Other | Corporate | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 6.50% | 6.50% |
Total long-term debt | $ 200 | $ 200 |
Corporate and Other | Corporate | Unsecured | Fixed Rate Unsecured US Senior Notes and Promissory Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 3.41% | 3.41% |
Total long-term debt | $ 4,398 | $ 4,046 |
Corporate and Other | Corporate | Unsecured | Fixed Rate 2.85% Senior Notes | ||
Debt Instrument [Line Items] | ||
Stated interest rate (percent) | 2.85% | 2.82% |
Total long-term debt | $ 500 | $ 500 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | |
Debt Instrument [Line Items] | ||
Maximum borrowing capacity | $ 5,165 | $ 4,952 |
Credit facilities unused | 3,920 | $ 3,943 |
Consolidated credit facilities | ||
Debt Instrument [Line Items] | ||
Maximum borrowing capacity | $ 5,200 | |
No one bank | Bank concentration risk | Credit facility | ||
Debt Instrument [Line Items] | ||
Concentration risk percentage | 20.00% | |
Committed facilities with maturities ranging from 2019 through 2023 | ||
Debt Instrument [Line Items] | ||
Maximum borrowing capacity | $ 5,000 | |
Fortis Inc. | Committed revolving corporate credit facility | ||
Debt Instrument [Line Items] | ||
Credit facilities unused | $ 1,000 | |
Maximum | ||
Debt Instrument [Line Items] | ||
Debt to capital restriction on issuance of new debt (percent) | 0.70 | |
Debt to capital restriction on dividends (percent) | 0.75 |
Long-Term Debt - Long-Term Debt
Long-Term Debt - Long-Term Debt Issuances (Details) $ in Millions | 1 Months Ended | |||||||||
Feb. 28, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Nov. 30, 2018USD ($) | Oct. 31, 2018USD ($) | Sep. 30, 2018CAD ($) | Aug. 31, 2018CAD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017CAD ($) | |
Debt Instrument [Line Items] | ||||||||||
Unsecured non-revolving term loan | $ 24,231 | $ 21,535 | ||||||||
ITC | 35-year 4.00% first mortgage bonds | Secured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.00% | |||||||||
Face value | $ 225,000,000 | |||||||||
ITC | 33-year 4.32% secured first mortgage bonds | Secured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.32% | |||||||||
Face value | $ 175,000,000 | |||||||||
UNS Energy | 30-Year 4.85% unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.85% | |||||||||
Face value | $ 300,000,000 | |||||||||
Central Hudson | 30-year 4.27% unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.27% | |||||||||
Face value | $ 25,000,000 | |||||||||
Central Hudson | 8-year 3.99% unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 3.99% | |||||||||
Face value | $ 40,000,000 | |||||||||
Central Hudson | 15-year 4.21% unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.21% | |||||||||
Face value | $ 40,000,000 | |||||||||
FortisBC Energy | 30-year 3.85% unsecured debentures | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 3.85% | 3.85% | ||||||||
Face value | $ 200 | |||||||||
FortisAlberta | 30-year 3.73% unsecured debentures | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 3.73% | |||||||||
Face value | $ 150 | |||||||||
FortisOntario | 30-year 4.10% unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.10% | |||||||||
Face value | $ 100 | |||||||||
Maritime Electric | 40-Year 4.15% first mortgage bonds | Secured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate (percent) | 4.15% | 4.15% | ||||||||
Face value | $ 40 | |||||||||
FortisTCI | 5-year floating rate unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Face value | $ 25,000,000 | |||||||||
FortisTCI | 5-year floating rate unsecured notes | Unsecured | LIBOR | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Variable rate (percent) | 1.75% | |||||||||
FortisTCI | 7-year floating unsecured notes | Unsecured | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Unsecured non-revolving term loan | $ 5,000,000 | |||||||||
Maximum borrowings | $ 10,000,000 |
Long-Term Debt - Long-Term De_2
Long-Term Debt - Long-Term Debt Repayments (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Disclosure [Abstract] | ||
Due within 1 year | $ 926 | |
Due in year 2 | 731 | |
Due in year 3 | 1,324 | |
Due in year 4 | 1,125 | |
Due in year 5 | 1,605 | |
Thereafter | 18,520 | |
Long-term Debt | $ 24,231 | $ 21,535 |
Long-Term Debt - Schedule of Cr
Long-Term Debt - Schedule of Credit Facilities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Line of Credit Facility [Line Items] | ||
Total credit facilities | $ 5,165 | $ 4,952 |
Credit facilities utilized: | ||
Short-term borrowings | (60) | (209) |
Long-term debt (including current portion) | (24,231) | (21,535) |
Letters of credit outstanding | (119) | (129) |
Credit facilities unused | 3,920 | 3,943 |
Current installments of long-term debt | $ 926 | $ 705 |
Credit facility | ||
Credit facilities utilized: | ||
Short-term debt weighted average interest rate (percent) | 4.20% | 1.80% |
Long-term debt weighted average interest rate (percent) | 3.30% | 2.50% |
Current installments of long-term debt | $ 735 | $ 312 |
Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (1,066) | (671) |
Long-term Credit Facility Borrowings | Credit facility | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (1,066) | (671) |
Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | (60) | $ (209) |
Regulated Utilities | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | 3,780 | |
Credit facilities utilized: | ||
Letters of credit outstanding | (65) | |
Credit facilities unused | 2,924 | |
Regulated Utilities | Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (731) | |
Regulated Utilities | Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | (60) | |
Corporate and Other | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | 1,385 | |
Credit facilities utilized: | ||
Letters of credit outstanding | (54) | |
Credit facilities unused | 996 | |
Corporate and Other | Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (335) | |
Corporate and Other | Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | $ 0 |
Long-Term Debt - Summary of Cre
Long-Term Debt - Summary of Credit Facility Balances (Details) $ in Millions | Dec. 31, 2018USD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) |
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 5,165 | $ 4,952 | |
ITC | Commercial paper | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 400,000,000 | ||
Amount outstanding | 0 | ||
Central Hudson | Uncommitted credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 40,000,000 | ||
FortisBC Electric | Demand overdraft | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 10 | ||
Other Electric | Unsecured demand overdraft facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 25 | ||
Other Electric | Unsecured demand facility and emergency standby loan | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 60,000,000 | ||
Fortis Inc. | Unsecured non-revolving facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 35 | ||
Regulated Utilities | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 3,780 | ||
Regulated Utilities | ITC | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 900,000,000 | ||
Regulated Utilities | UNS Energy | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 500,000,000 | ||
Regulated Utilities | Central Hudson | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 250,000,000 | ||
Regulated Utilities | Central Hudson | Revolving credit facility | First redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 50,000,000 | ||
Regulated Utilities | Central Hudson | Revolving credit facility | Second redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 200,000,000 | ||
Regulated Utilities | FortisBC Energy | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 700 | ||
Regulated Utilities | FortisAlberta | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 250 | ||
Regulated Utilities | FortisBC Electric | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 150 | ||
Regulated Utilities | Other Electric | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 50,000,000 | 190 | |
Regulated Utilities | Other Electric | Revolving credit facility | First redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 50 | ||
Regulated Utilities | Other Electric | Revolving credit facility | Second redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 40 | ||
Regulated Utilities | Other Electric | Revolving credit facility | Third redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 100 | ||
Corporate and Other | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,385 | ||
Corporate and Other | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,350 | ||
Option to increase the facility | 500 | ||
Corporate and Other | Revolving credit facility | First redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,300 | ||
Corporate and Other | Revolving credit facility | Second redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 50 |
Capital Lease and Finance Obl_3
Capital Lease and Finance Obligations - UNS Energy (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2019CAD ($) | Dec. 31, 2018USD ($)lease | Dec. 31, 2018CAD ($)lease | |
Capital Leased Assets [Line Items] | ||||||
Total lease obligations | $ 642 | |||||
Gila River Common Facilities | UNS Energy | ||||||
Capital Leased Assets [Line Items] | ||||||
Lease term (years) | 20 years | |||||
Demand Charge | $ 10 | $ 0 | ||||
Springerville Common Facilities | UNS Energy | ||||||
Capital Leased Assets [Line Items] | ||||||
Interest rate | 5.77% | 5.77% | ||||
Amortized principal balance | 23 | $ 16 | ||||
Total lease obligations | 26 | $ 19 | ||||
Interest expense | 3 | 4 | ||||
Depreciation expense related to assets under capital lease | $ 8 | $ 8 | ||||
Springerville Common Facilities | UNS Energy | Capital Leases | LIBOR | ||||||
Capital Leased Assets [Line Items] | ||||||
Variable rate (percent) | 2.00% | |||||
Springerville Common Facilities | TEP | ||||||
Capital Leased Assets [Line Items] | ||||||
Total number of capital lease obligations | lease | 2 | 2 | ||||
Fixed-price purchase provision | $ 68 | |||||
Springerville Common Facilities | TEP | Minimum | ||||||
Capital Leased Assets [Line Items] | ||||||
Lease renewal term | 2 years | |||||
Forecast | Gila River Common Facilities | UNS Energy | ||||||
Capital Leased Assets [Line Items] | ||||||
Estimated purchase option | $ 164 | $ 224 |
Capital Lease and Finance Obl_4
Capital Lease and Finance Obligations - FortisBC Electric (Details) - FortisBC Electric - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Brilliant Plant | ||
Capital Leased Assets [Line Items] | ||
Concentration purchased output percentage | 94.00% | |
Capital lease costs recognized in energy supply costs and operating expenses | $ 28 | $ 27 |
Brilliant Plant | Capital Leases | ||
Capital Leased Assets [Line Items] | ||
Stated interest rate (percent) | 5.00% | |
BTS | ||
Capital Leased Assets [Line Items] | ||
Capital lease costs recognized in energy supply costs and operating expenses | $ 3 | $ 3 |
BTS | Capital Leases | ||
Capital Leased Assets [Line Items] | ||
Stated interest rate (percent) | 9.00% |
Capital Lease and Finance Obl_5
Capital Lease and Finance Obligations - Finance Obligations (Details) - FortisBC Energy - Natural gas distribution assets - CAD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Oct. 31, 2018 | Dec. 31, 2018 | |
Capital Leased Assets [Line Items] | ||
Lease term (years) | 35 years | |
Contract termination option (years) | 17 years | |
Capital Leases | ||
Capital Leased Assets [Line Items] | ||
Early termination payment | $ 27 | |
Capital Leases | Minimum | ||
Capital Leased Assets [Line Items] | ||
Stated interest rate (percent) | 6.90% | |
Capital Leases | Maximum | ||
Capital Leased Assets [Line Items] | ||
Stated interest rate (percent) | 7.48% |
Capital Lease and Finance Obl_6
Capital Lease and Finance Obligations - Repayment of Capital Lease and Finance Obligations (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Leases [Abstract] | ||
Due within 1 year | $ 313 | |
Due in year 2 | 77 | |
Due in year 3 | 80 | |
Due in year 4 | 49 | |
Due in year 5 | 47 | |
Thereafter | 1,885 | |
Total | 2,451 | |
Less: Imputed interest and executory costs | (1,809) | |
Total capital lease and finance obligations | 642 | |
Less: Current installments | (252) | $ (47) |
Capital lease and finance obligations, noncurrent portion | $ 390 | $ 414 |
Other Liabilities - Schedule of
Other Liabilities - Schedule of Other Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Other Liabilities Disclosure [Abstract] | ||
Defined benefit pension plans (Note 25) | $ 391 | $ 393 |
OPEBs (Note 25) | 350 | 381 |
Asset retirement obligations (Note 3) | 111 | 71 |
Customer and other deposits | 57 | 67 |
Stock-based compensation plans (Note 22) | 56 | 39 |
Mine reclamation obligations | 40 | 40 |
Manufactured gas plant site remediation | 32 | 34 |
Fair value of derivatives (Note 28) | 30 | 37 |
Deferred compensation plan (Note 11) | 29 | 28 |
Debt Instrument [Line Items] | ||
Other | 42 | 57 |
Other liabilities | 1,138 | 1,210 |
Waneta Partnership | Waneta Partnership promissory note | ||
Debt Instrument [Line Items] | ||
Waneta Partnership promissory note | $ 0 | $ 63 |
Other Liabilities - Schedule _2
Other Liabilities - Schedule of Other Liabilities Footnotes (Details) $ in Millions, $ in Millions | Dec. 31, 2018USD ($)mine | Dec. 31, 2018CAD ($)mine |
TEP | ||
Debt Instrument [Line Items] | ||
Expected reclamation costs | $ 66 | $ 90 |
TEP | Coal mine reclamation | ||
Debt Instrument [Line Items] | ||
Number of mines | 3 | 3 |
Central Hudson | ||
Debt Instrument [Line Items] | ||
Remediation cost obligation | $ 47 | $ 64 |
Central Hudson | Accounts payable and other current liabilities | ||
Debt Instrument [Line Items] | ||
Remediation cost obligation | $ 23 | $ 32 |
Earnings Per Common Share (Deta
Earnings Per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Net Earnings to Common Shareholders | ||
Basic EPS | $ 1,100 | $ 963 |
Potential dilutive effect of stock options | 0 | 0 |
Diluted EPS | $ 1,100 | $ 963 |
Weighted Average Shares | ||
Basic EPS (shares) | 424.7 | 415.5 |
Stock Options (shares) | 0.5 | 0.7 |
Diluted EPS (shares) | 425.2 | 416.2 |
EPS | ||
Basic (CAD per share) | $ 2.59 | $ 2.32 |
Diluted (CAD per share) | $ 2.59 | $ 2.31 |
Preference Shares - Issued and
Preference Shares - Issued and outstanding (Details) - CAD ($) shares in Thousands, $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 66,200 | 66,200 |
Preference stock issued | $ 1,623 | $ 1,623 |
Preferred stock outstanding (shares) | 66,200 | 66,200 |
Preferred stock outstanding | $ 1,623 | $ 1,623 |
Series F | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 5,000 | 5,000 |
Preference stock issued | $ 122 | $ 122 |
Preferred stock outstanding (shares) | 5,000 | 5,000 |
Preferred stock outstanding | $ 122 | $ 122 |
Series G | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 9,200 | 9,200 |
Preference stock issued | $ 225 | $ 225 |
Preferred stock outstanding (shares) | 9,200 | 9,200 |
Preferred stock outstanding | $ 225 | $ 225 |
Series H | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 7,025 | 7,025 |
Preference stock issued | $ 172 | $ 172 |
Preferred stock outstanding (shares) | 7,025 | 7,025 |
Preferred stock outstanding | $ 172 | $ 172 |
Series I | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 2,975 | 2,975 |
Preference stock issued | $ 73 | $ 73 |
Preferred stock outstanding (shares) | 2,975 | 2,975 |
Preferred stock outstanding | $ 73 | $ 73 |
Series J | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 8,000 | 8,000 |
Preference stock issued | $ 196 | $ 196 |
Preferred stock outstanding (shares) | 8,000 | 8,000 |
Preferred stock outstanding | $ 196 | $ 196 |
Series K | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 10,000 | 10,000 |
Preference stock issued | $ 244 | $ 244 |
Preferred stock outstanding (shares) | 10,000 | 10,000 |
Preferred stock outstanding | $ 244 | $ 244 |
Series M | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 24,000 | 24,000 |
Preference stock issued | $ 591 | $ 591 |
Preferred stock outstanding (shares) | 24,000 | 24,000 |
Preferred stock outstanding | $ 591 | $ 591 |
Preference Shares - Schedule of
Preference Shares - Schedule of Characteristics of First Preference Shares (Details) | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||
Dec. 31, 2018$ / shares | Aug. 31, 2018$ / shares | Dec. 31, 2018$ / shares | Dec. 01, 2021$ / shares | Jun. 01, 2020$ / shares | Dec. 01, 2018$ / shares | |
Class of Stock [Line Items] | ||||||
Preferred shares rate dividend term | 5 years | |||||
Series F | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 4.90% | |||||
Annual Dividend (CAD per share) | $ 1.2250 | |||||
Reset Dividend Yield (percent) | 0.00% | |||||
Redemption price (CAD per share) | $ 25 | $ 25 | ||||
Series J | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 4.75% | |||||
Annual Dividend (CAD per share) | $ 1.1875 | |||||
Reset Dividend Yield (percent) | 0.00% | |||||
Redemption price (CAD per share) | 25.75 | $ 25.75 | $ 26 | |||
Preferred stock redemption price per share annual decrease (CAD per share) | $ 0.25 | |||||
Series J | Forecast | ||||||
Class of Stock [Line Items] | ||||||
Redemption price (CAD per share) | $ 25 | |||||
Series G | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 5.25% | |||||
Annual Dividend (CAD per share) | 1.0983 | $ 0.9708 | ||||
Reset Dividend Yield (percent) | 2.13% | |||||
Redemption price (CAD per share) | 25 | $ 25 | ||||
Series H | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 4.25% | |||||
Annual Dividend (CAD per share) | $ 0.6250 | |||||
Reset Dividend Yield (percent) | 1.45% | |||||
Redemption price (CAD per share) | $ 25 | $ 25 | ||||
Preferred shares exchange ratio | 1 | 1 | ||||
Series K | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 4.00% | |||||
Annual Dividend (CAD per share) | $ 1 | |||||
Reset Dividend Yield (percent) | 2.05% | |||||
Redemption price (CAD per share) | $ 25 | $ 25 | ||||
Preferred shares exchange ratio | 1 | 1 | ||||
Series M | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 4.10% | |||||
Annual Dividend (CAD per share) | $ 1.0250 | |||||
Reset Dividend Yield (percent) | 2.48% | |||||
Redemption price (CAD per share) | $ 25 | $ 25 | ||||
Preferred shares exchange ratio | 1 | 1 | ||||
Series I | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 2.10% | |||||
Annual Dividend (CAD per share) | $ 0 | |||||
Reset Dividend Yield (percent) | 1.45% | |||||
Redemption price (CAD per share) | $ 25.50 | $ 25.50 | ||||
Preferred shares exchange ratio | 1 | 1 | ||||
Series I | Forecast | ||||||
Class of Stock [Line Items] | ||||||
Redemption price (CAD per share) | $ 25 | |||||
Series L | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 0.00% | |||||
Annual Dividend (CAD per share) | $ 0 | |||||
Reset Dividend Yield (percent) | 2.05% | |||||
Redemption price (CAD per share) | $ 0 | $ 0 | ||||
Preferred shares exchange ratio | 1 | 1 | ||||
Series N | ||||||
Class of Stock [Line Items] | ||||||
Initial yield (percent) | 0.00% | |||||
Annual Dividend (CAD per share) | $ 0 | |||||
Reset Dividend Yield (percent) | 2.48% | |||||
Redemption price (CAD per share) | $ 0 | $ 0 | ||||
Preferred shares exchange ratio | 1 | 1 | ||||
Fixed rate reset | ||||||
Class of Stock [Line Items] | ||||||
Redemption price (CAD per share) | $ 25 | $ 25 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accumulated other comprehensive income | ||
Beginning balance | $ 15,003 | |
Ending balance | 16,533 | $ 15,003 |
On net investments in foreign operations | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | 247 | 1,227 |
Other comprehensive income (loss), before tax | 1,223 | (980) |
Accumulated other comprehensive income (loss), before tax, ending balance | 1,470 | 247 |
On hedges of net investments in foreign operations | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (172) | (472) |
Other comprehensive income (loss), before tax | (372) | 300 |
Accumulated other comprehensive income (loss), before tax, ending balance | (544) | (172) |
Net unrealized foreign currency translation gains (losses) | ||
Accumulated other comprehensive income | ||
Beginning balance | 74 | 756 |
Income tax recovery (expense), opening balance | (1) | 1 |
Other comprehensive income (loss), tax recovery (expense) | 11 | (2) |
Other comprehensive income (loss) | 862 | (682) |
Income tax recovery (expense), opening balance | 10 | (1) |
Ending balance | 936 | 74 |
Cash flow hedges (Note 28) | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | 10 | 8 |
Other comprehensive income (loss), before tax | 1 | 2 |
Accumulated other comprehensive income (loss), before tax, ending balance | 11 | 10 |
Unrealized employee future benefits (losses) gains (Note 25) | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (26) | (22) |
Other comprehensive income (loss), before tax | 6 | (4) |
Accumulated other comprehensive income (loss), before tax, ending balance | (20) | (26) |
Cash flow hedges and unrealized employee future benefits (losses) gains | ||
Accumulated other comprehensive income | ||
Beginning balance | (13) | (11) |
Income tax recovery (expense), opening balance | 3 | 3 |
Other comprehensive income (loss), tax recovery (expense) | (2) | 0 |
Other comprehensive income (loss) | 5 | (2) |
Income tax recovery (expense), opening balance | 1 | 3 |
Ending balance | (8) | (13) |
Accumulated other comprehensive income | ||
Accumulated other comprehensive income | ||
Beginning balance | 61 | 745 |
Other comprehensive income (loss) | 867 | (684) |
Ending balance | $ 928 | $ 61 |
Stock-based Compensation Plan_2
Stock-based Compensation Plans - Stock Options (Details) - Options | 12 Months Ended |
Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Exercisable period | 10 years |
Expiration period after termination, death or retirement | 3 years |
Award vesting period | 4 years |
Stock-based Compensation Plan_3
Stock-based Compensation Plans - Stock Options, Fair Value Assumptions (Details) - $ / shares | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2018 | Feb. 28, 2018 | Feb. 28, 2017 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options granted (shares) | 761,508 | |||
Exercise price (CAD per share) | $ 41.31 | |||
Grant date fair value (CAD per share) | $ 3.46 | |||
Options | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options granted (shares) | 39,972 | 721,536 | 774,924 | |
Exercise price (CAD per share) | $ 42 | $ 41.27 | $ 42.36 | |
Grant date fair value (CAD per share) | $ 4.08 | $ 3.43 | $ 3.22 | |
Valuation assumptions: | ||||
Dividend yield (percent) | 3.70% | 3.70% | 3.80% | |
Expected volatility (percent) | 15.70% | 15.50% | 16.10% | |
Risk-free interest rate | 2.00% | 2.10% | 1.20% | |
Weighted average expected life (years) | 5 years 7 months 6 days | 5 years 7 months 6 days | 5 years 7 months 6 days | |
Volume weighted average share price (period) | 5 days |
Stock-based Compensation Plan_4
Stock-based Compensation Plans - Stock Option Activity (Details) - CAD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2018 | Feb. 28, 2018 | Feb. 28, 2017 | Dec. 31, 2018 | |
Total Options, Number of Options | ||||
Options outstanding, beginning balance (shares) | 3,702,294 | |||
Granted (shares) | 761,508 | |||
Exercised (shares) | (357,120) | |||
Cancelled/Forfeited (shares) | (91,216) | |||
Options outstanding, ending balance (shares) | 4,015,466 | |||
Options vested, number of options (shares) | 2,244,339 | |||
Total Options, Weighted Average Exercise Price | ||||
Options outstanding, beginning balance (CAD per share) | $ 36.65 | |||
Granted (CAD per share) | 41.31 | |||
Exercised (CAD per share) | 33.49 | |||
Cancelled/Forfeited (CAD per share) | 40.44 | |||
Options outstanding, ending balance (CAD per share) | 37.73 | |||
Options vested, weighted average exercise price (CAD per share) | $ 35.40 | |||
Non-vested Options, Number of Options | ||||
Options outstanding, beginning balance (shares) | 1,812,319 | |||
Granted (shares) | 761,508 | |||
Vested (shares) | (711,484) | |||
Cancelled/Forfeited (shares) | (91,216) | |||
Options outstanding, ending balance (shares) | 1,771,127 | |||
Non-vested Options, Weighted Average Grant Date Fair Value | ||||
Options outstanding, beginning balance (CAD per share) | $ 2.86 | |||
Granted (CAD per share) | 3.46 | |||
Vested (CAD per share) | 2.88 | |||
Cancelled/Forfeited (CAD per share) | 3.08 | |||
Options outstanding, ending balance (CAD per share) | $ 3.10 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation expense | $ 5 | |||
Weighted average remaining term of vested options | 6 years | |||
Aggregate intrinsic value | $ 23 | |||
Options | ||||
Total Options, Number of Options | ||||
Granted (shares) | 39,972 | 721,536 | 774,924 | |
Total Options, Weighted Average Exercise Price | ||||
Granted (CAD per share) | $ 42 | $ 41.27 | $ 42.36 | |
Non-vested Options, Number of Options | ||||
Granted (shares) | 39,972 | 721,536 | 774,924 | |
Non-vested Options, Weighted Average Grant Date Fair Value | ||||
Granted (CAD per share) | $ 4.08 | $ 3.43 | $ 3.22 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Remaining weighted average period to recognize compensation expense (years) | 3 years |
Stock-based Compensation Plan_5
Stock-based Compensation Plans - Schedule of Additional Stock Option Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Stock options exercised: | ||
Cash received for exercise price | $ 12 | $ 40 |
Intrinsic value realized by employees | 3 | 15 |
Fair value of options that vested | 2 | 2 |
Options | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock option expense recognized | $ 2 | $ 3 |
Stock-based Compensation Plan_6
Stock-based Compensation Plans - Directors' DSU Plan (Details) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)$ / sharesshares | Dec. 31, 2017CAD ($)$ / sharesshares | |
Number of DSUs | ||
Accrued liability | $ | $ 56 | $ 39 |
Director | DSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unit with underlying value equivalent to common shares | 1 | |
Number of DSUs | ||
DSUs outstanding, beginning of year (shares) | 184,795 | 199,411 |
Granted (shares) | 32,132 | 31,453 |
Granted - notional dividends reinvested (shares) | 7,518 | 7,294 |
DSUs paid out (shares) | (47,898) | (53,363) |
DSUs outstanding, end of year (shares) | 176,547 | 184,795 |
Compensation expense recognized | $ | $ 2 | $ 3 |
Cash payout | $ | 2 | 2 |
Accrued liability | $ | $ 8 | $ 9 |
Weighted-average payout price (CAD per share) | $ / shares | $ 43.15 | $ 45.37 |
Stock-based Compensation Plan_7
Stock-based Compensation Plans - PSU Plans (Details) - PSUs | 12 Months Ended |
Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting period | 3 years |
Unit with underlying value equivalent to common shares | 1 |
Volume weighted average share price (period) | 5 days |
Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Payout (percent) | 0.00% |
Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Payout (percent) | 200.00% |
Stock-based Compensation Plan_8
Stock-based Compensation Plans - Schedule of PSU and RSU Plans Activity (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
PSUs | ||
Number of Units | ||
Outstanding, beginning of year (shares) | 1,350,960 | 931,951 |
Granted (shares) | 668,995 | 711,749 |
Granted - notional dividends reinvested (shares) | 66,280 | 44,893 |
Paid out (shares) | (280,993) | (239,509) |
Cancelled/forfeited (shares) | (42,471) | (16,910) |
Transferred in (out) (shares) | 0 | (81,214) |
Outstanding, end of year (shares) | 1,762,771 | 1,350,960 |
Additional Information (in millions) | ||
Compensation expense recognized | $ 22 | $ 26 |
Compensation expense unrecognized | 27 | 17 |
Cash payout | 14 | 11 |
Accrued liability as at December 31 | 50 | 41 |
Aggregate intrinsic value as at December 31 | $ 77 | $ 58 |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Weighted-average payout price (CAD per share) | $ 46.01 | $ 41.46 |
Payout percentage | 109.00% | 113.00% |
Weighted-average contractual life (years) | 1 year | |
RSUs | ||
Number of Units | ||
Outstanding, beginning of year (shares) | 482,763 | 123,612 |
Granted (shares) | 305,686 | 349,496 |
Granted - notional dividends reinvested (shares) | 26,263 | 15,407 |
Paid out (shares) | (75,427) | (74,876) |
Cancelled/forfeited (shares) | (22,267) | (12,090) |
Transferred in (out) (shares) | 0 | 81,214 |
Outstanding, end of year (shares) | 717,018 | 482,763 |
Additional Information (in millions) | ||
Compensation expense recognized | $ 11 | $ 8 |
Compensation expense unrecognized | 15 | 11 |
Cash payout | 3 | 3 |
Accrued liability as at December 31 | 19 | 11 |
Aggregate intrinsic value as at December 31 | $ 34 | $ 22 |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Weighted-average payout price (CAD per share) | $ 45.55 | $ 43.42 |
Weighted-average contractual life (years) | 1 year |
Stock-based Compensation Plan_9
Stock-based Compensation Plans - RSU Plans (Details) - RSUs | 12 Months Ended |
Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting period | 3 years |
Unit with underlying value equivalent to common shares | 1 |
Other Income, Net (Details)
Other Income, Net (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | ||
Equity component of AFUDC | $ 64 | $ 74 |
Interest income | 15 | 14 |
Entity Information [Line Items] | ||
Pension and Other Postretirement Benefits Cost (Reversal of Cost) | 1 | 11 |
Net foreign exchange gain | 0 | 26 |
Other | (17) | 9 |
Other income, net | 60 | 116 |
Unrealized foreign exchange gain | 21 | |
BEL | ||
Entity Information [Line Items] | ||
Equity (loss) income - BEL | $ (1) | $ 4 |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Income Tax Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Gross deferred income tax assets | ||
Regulatory liabilities | $ 635 | $ 596 |
Tax loss and credit carryforwards | 522 | 571 |
Employee future benefits | 153 | 143 |
Unrealized foreign exchange losses on long-term debt | 69 | 28 |
Other | 76 | 51 |
Deferred tax assets, gross | 1,455 | 1,389 |
Valuation allowance | (56) | (44) |
Net deferred income tax asset | 1,399 | 1,345 |
Gross deferred income tax liabilities | ||
PPE | (3,780) | (3,353) |
Regulatory assets | (203) | (203) |
Intangible assets | (102) | (87) |
Deferred tax liabilities, gross | (4,085) | (3,643) |
Net deferred income tax liability | $ (2,686) | $ (2,298) |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | ||
Unrealized foreign exchange losses on long‑term debt and tax loss and credit carryforwards | $ 56,000,000 | $ 44,000,000 |
Unrecognized tax benefits that would impact tax expenses | 1,000,000 | |
Unrecognized tax benefits, interest expense | $ 0 | $ 0 |
Income Taxes - Summary of Unrec
Income Taxes - Summary of Unrecognized Tax Benefits (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning of year | $ 28 | $ 23 |
Additions related to the current year | 6 | 13 |
Adjustments related to prior years and U.S. Tax Reform | 4 | |
Adjustments related to prior years and U.S. Tax Reform | (8) | |
End of year | $ 38 | $ 28 |
Income Taxes - Schedule of Comp
Income Taxes - Schedule of Components of Income Tax Expense (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Canadian | ||
Earnings before income tax expense | $ 376 | $ 461 |
Current income tax | 51 | 41 |
Deferred income tax | (25) | 16 |
Total Canadian | 26 | 57 |
Foreign | ||
Earnings before income tax expense | 1,075 | 1,252 |
Current income tax | (22) | 3 |
Deferred income tax | 161 | 528 |
Total Foreign | 139 | 531 |
Income tax expense | $ 165 | $ 588 |
Income Taxes - Schedule of Effe
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | ||
Earnings before income tax expense | $ 1,451 | $ 1,713 |
Combined Canadian federal and provincial statutory income tax rate | 28.50% | 28.00% |
Expected federal and provincial taxes at statutory rate | $ 414 | $ 480 |
Expected federal and provincial taxes at statutory rate Increase (decrease) resulting from: | ||
Enactment of U.S. Tax Reform | 0 | 168 |
Foreign and other statutory rate differentials | (110) | 31 |
Remeasurement of deferred tax liabilities | (44) | 0 |
AFUDC | (14) | (26) |
Effects of rate-regulated accounting: | ||
Difference between depreciation claimed for income tax and accounting purposes | (34) | (26) |
Items capitalized for accounting purposes but expensed for income tax purposes | (21) | (21) |
Other | (26) | (18) |
Income tax expense | $ 165 | $ 588 |
Effective tax rate | 11.40% | 34.30% |
Earnings impact | $ 168 | |
Earnings impact on parent | $ 146 |
Income Taxes - Tax Carryforward
Income Taxes - Tax Carryforward (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Tax Credit Carryforward [Line Items] | |
Total income tax carryforwards recognized as at December 31 | $ 2,678 |
Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax carryforward, gross | 448 |
Unrecognized | (15) |
Total income tax carryforwards recognized as at December 31 | 433 |
Foreign | |
Tax Credit Carryforward [Line Items] | |
Federal and state net operating loss | 2,130 |
Tax carryforward, gross | 2,245 |
Capital loss | Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | 59 |
Non-capital loss | Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | 387 |
Other tax credits | Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | 2 |
Other tax credits | Foreign | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | $ 115 |
Employee Future Benefits - Sche
Employee Future Benefits - Schedule of Allocation of Plan Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | |||
2018 Target Allocation | 100.00% | ||
Actual Plan Asset Allocations (percent) | 100.00% | 100.00% | |
Fair value of plan assets | $ 3,123 | $ 3,118 | |
Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2018 Target Allocation | 46.00% | ||
Actual Plan Asset Allocations (percent) | 45.00% | 47.00% | |
Fair value of plan assets | $ 1,393 | $ 1,471 | |
Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2018 Target Allocation | 47.00% | ||
Actual Plan Asset Allocations (percent) | 47.00% | 46.00% | |
Fair value of plan assets | $ 1,482 | $ 1,422 | |
Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2018 Target Allocation | 6.00% | ||
Actual Plan Asset Allocations (percent) | 7.00% | 6.00% | |
Fair value of plan assets | $ 204 | $ 181 | |
Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 25 | $ 22 | |
Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2018 Target Allocation | 1.00% | ||
Actual Plan Asset Allocations (percent) | 1.00% | 1.00% | |
Fair value of plan assets | $ 19 | $ 22 | |
Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 660 | 663 | |
Level 1 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 508 | 522 | |
Level 1 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 144 | 133 | |
Level 1 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 1 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 1 | Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 8 | 8 | |
Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 2,248 | 2,265 | |
Level 2 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 885 | 949 | |
Level 2 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,338 | 1,289 | |
Level 2 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 14 | 13 | |
Level 2 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 | Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 11 | 14 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 215 | 190 | $ 113 |
Level 3 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 190 | 168 | |
Level 3 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 25 | 22 | |
Level 3 | Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 0 | $ 0 |
Employee Future Benefits - Sc_2
Employee Future Benefits - Schedule of Level 3 Changes in Plan Assets (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | $ 3,118 | |
Balance, end of year | 3,123 | $ 3,118 |
Level 3 | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | 190 | 113 |
Return on plan assets | 15 | 12 |
Foreign currency translation | 3 | (2) |
Purchases, sales and settlements | 7 | 67 |
Balance, end of year | $ 215 | $ 190 |
Employee Future Benefits - Sc_3
Employee Future Benefits - Schedule of Funded Status (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Change in value of plan assets | ||
Balance, beginning of year | $ 3,118 | |
Balance, end of year | 3,123 | $ 3,118 |
Defined Benefit Pension Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 3,215 | 3,037 |
Service costs | 84 | 76 |
Employee contributions | 16 | 16 |
Interest costs | 114 | 115 |
Benefits paid | (145) | (133) |
Actuarial losses (gains) | (217) | 217 |
Past service credits/plan amendments | (1) | 0 |
Foreign currency translation | 141 | (113) |
Balance, end of year | 3,207 | 3,215 |
Change in value of plan assets | ||
Balance, beginning of year | 2,841 | 2,646 |
Actual return on plan assets | (93) | 336 |
Benefits paid | (137) | (127) |
Employee contributions | 16 | 16 |
Employer contributions | 79 | 69 |
Foreign currency translation | 124 | (99) |
Balance, end of year | 2,830 | 2,841 |
Funded status | (377) | (374) |
Long-term assets (Note 11) | 26 | 31 |
Current liabilities (Note 15) | (12) | (12) |
Long-term liabilities (Note 18) | (391) | (393) |
Net liabilities | (377) | (374) |
Accumulated benefit obligation | 2,936 | 2,940 |
OPEB Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 665 | 676 |
Service costs | 31 | 27 |
Employee contributions | 2 | 2 |
Interest costs | 23 | 25 |
Benefits paid | (26) | (22) |
Actuarial losses (gains) | (69) | (14) |
Past service credits/plan amendments | (3) | (3) |
Foreign currency translation | 32 | (26) |
Balance, end of year | 655 | 665 |
Change in value of plan assets | ||
Balance, beginning of year | 277 | 252 |
Actual return on plan assets | (13) | 37 |
Benefits paid | (26) | (22) |
Employee contributions | 2 | 2 |
Employer contributions | 29 | 26 |
Foreign currency translation | 24 | (18) |
Balance, end of year | 293 | 277 |
Funded status | (362) | (388) |
Long-term assets (Note 11) | 1 | 3 |
Current liabilities (Note 15) | (13) | (10) |
Long-term liabilities (Note 18) | (350) | (381) |
Net liabilities | $ (362) | $ (388) |
Employee Future Benefits - Sc_4
Employee Future Benefits - Schedule of Net Benefit Costs (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | $ 84 | $ 76 |
Interest costs | 114 | 115 |
Expected return on plan assets | (162) | (151) |
Amortization of actuarial losses | 48 | 45 |
Amortization of past service credits/plan amendments | 0 | 0 |
Regulatory adjustments | (1) | 2 |
Net benefit cost | 83 | 87 |
OPEB Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | 31 | 27 |
Interest costs | 23 | 25 |
Expected return on plan assets | (16) | (14) |
Amortization of actuarial losses | 0 | 2 |
Amortization of past service credits/plan amendments | (10) | (12) |
Regulatory adjustments | 6 | 4 |
Net benefit cost | $ 34 | $ 32 |
Employee Future Benefits - Comp
Employee Future Benefits - Components of AOCI and Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Regulatory assets (Note 9) | $ 3,178 | $ 3,045 |
Regulatory liabilities (Note 9) | (3,626) | (3,446) |
Defined Benefit Pension Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses (gains) | 19 | 22 |
Unamortized past service costs | 1 | 1 |
Income tax recovery | (3) | (5) |
Accumulated other comprehensive income (Note 21) | 17 | 18 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses (gains) | 457 | 443 |
Past service credits | (10) | (11) |
Other regulatory deferrals | 15 | 10 |
Net regulatory assets | 462 | 442 |
Regulatory assets (Note 9) | 462 | 442 |
Regulatory liabilities (Note 9) | 0 | 0 |
OPEB Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses (gains) | (2) | 0 |
Unamortized past service costs | 2 | 3 |
Income tax recovery | (1) | (1) |
Accumulated other comprehensive income (Note 21) | (1) | 2 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses (gains) | (25) | 17 |
Past service credits | (16) | (23) |
Other regulatory deferrals | 27 | 27 |
Net regulatory assets | (14) | 21 |
Regulatory assets (Note 9) | 23 | 68 |
Regulatory liabilities (Note 9) | $ (37) | $ (47) |
Employee Future Benefits - Co_2
Employee Future Benefits - Components Recognized in OCI and Regulatory Assets (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial (gains) losses | $ (3) | $ 5 |
Past service (credits) costs/plan amendments | 0 | 0 |
Amortization of actuarial losses | (1) | (1) |
Foreign currency translation | 1 | (1) |
Income tax recovery | 2 | 0 |
Total recognized in comprehensive income | (1) | 3 |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Current year net actuarial losses (gains) | 41 | 24 |
Past service credits/plan amendments | 0 | 0 |
Amortization of actuarial losses | (47) | (44) |
Amortization of past service (costs) credits | 1 | 0 |
Foreign currency translation | 21 | (17) |
Regulatory adjustments | 4 | (1) |
Total recognized in regulatory assets | 20 | (38) |
Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract] | ||
Future amortization of loss from AOCI | 1 | |
Defined Benefit Plan, Amount to be Amortized from Regulatory Asset Next Fiscal Year [ [Abstract] | ||
Future amortization of loss from regulatory asset | 24 | |
Future amortization of prior service credit from regulatory asset | 1 | |
Future amorization of regulatory adjustments from regulatory asset | 1 | |
OPEB Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial (gains) losses | (2) | (1) |
Past service (credits) costs/plan amendments | (1) | 2 |
Amortization of actuarial losses | 0 | 0 |
Foreign currency translation | 0 | 0 |
Income tax recovery | 0 | 0 |
Total recognized in comprehensive income | (3) | 1 |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Current year net actuarial losses (gains) | (39) | (35) |
Past service credits/plan amendments | (3) | (5) |
Amortization of actuarial losses | 0 | (1) |
Amortization of past service (costs) credits | 11 | 12 |
Foreign currency translation | (3) | 2 |
Regulatory adjustments | (1) | (6) |
Total recognized in regulatory assets | (35) | $ (33) |
Defined Benefit Plan, Amount to be Amortized from Regulatory Asset Next Fiscal Year [ [Abstract] | ||
Future amortization of loss from regulatory asset | (4) | |
Future amortization of prior service credit from regulatory asset | 8 | |
Future amorization of regulatory adjustments from regulatory asset | $ 4 |
Employee Future Benefits - Sc_5
Employee Future Benefits - Schedule of Assumptions Used (Details) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 3.56% | 3.98% |
Discount rate as at December 31 | 4.07% | 3.58% |
Expected long-term rate of return on plan assets | 5.80% | 5.97% |
Rate of compensation increase | 3.35% | 3.34% |
Health care cost trend increase as at December 31 | 0.00% | 0.00% |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 3.57% | 3.96% |
Discount rate as at December 31 | 4.13% | 3.59% |
Expected long-term rate of return on plan assets | 5.48% | 5.81% |
Rate of compensation increase | 0.00% | 0.00% |
Health care cost trend increase as at December 31 | 4.61% | 4.71% |
Health care cost trend rate assumed for next fiscal year | 6.35% | |
Remaining period until health care cost trend rate reaches ultimate trend rate | 14 years | |
Year that rate reaches ultimate trend rate | 2,032 |
Employee Future Benefits - Effe
Employee Future Benefits - Effect of Changing Health Care Cost Trend Rate by 1% (Details) - OPEB Plans $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |
1% increase in rate, increase (decrease) in accumulated benefit obligation | $ 85 |
1% decrease in rate, increase (decrease) in accumulated benefit obligation Obligation | (67) |
1% increase in rate, increase (decrease) in service and interest costs | 11 |
1% decrease in rate, increase (decrease) in service and interest costs | $ (8) |
Employee Future Benefits - Sc_6
Employee Future Benefits - Schedule of Expected Benefit Payments (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Defined Benefit | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2,019 | $ 147 |
2,020 | 152 |
2,021 | 157 |
2,022 | 165 |
2,023 | 170 |
2024-2028 | 946 |
OPEB Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2,019 | 26 |
2,020 | 28 |
2,021 | 30 |
2,022 | 32 |
2,023 | 33 |
2024-2028 | $ 185 |
Employee Future Benefits - Defi
Employee Future Benefits - Defined Contribution Plan (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Defined contribution plan cost recognized | $ 38 | $ 38 |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Expected contributions for next fiscal year | 47 | |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Expected contributions for next fiscal year | $ 31 |
Terminated Acquisition (Details
Terminated Acquisition (Details) - Teck Waneta Dam and related transmission assets - CAD ($) $ in Millions | 1 Months Ended | |
Aug. 31, 2017 | May 31, 2017 | |
Business Acquisition [Line Items] | ||
Ownership interest | 66.67% | |
Break fee | $ 28 |
Supplementary Cash Flow Infor_3
Supplementary Cash Flow Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Cash paid for | ||
Interest | $ 969 | $ 927 |
Income taxes | 73 | 69 |
Change in working capital | ||
Accounts receivable and other current assets | (204) | (74) |
Prepaid expenses | 1 | (3) |
Inventories | (8) | (6) |
Regulatory assets - current portion | 16 | 39 |
Accounts payable and other current liabilities | 99 | 119 |
Regulatory liabilities - current portion | (6) | (172) |
Changes in non-cash operating working capital | (102) | (97) |
Non-cash investing and financing activities | ||
Accrued capital expenditures | 328 | 307 |
Common share dividends reinvested | 272 | 253 |
Gila River generating station Unit 2 capital lease | 223 | 0 |
Contributions in aid of construction | 14 | 35 |
Exercise of stock options into common shares | $ 1 | $ 5 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments and Risk Management - Derivatives Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018CAD ($)derivative | Dec. 31, 2017CAD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Regulatory assets | $ 3,178 | $ 3,045 |
Regulatory liability | 3,626 | 3,446 |
Gains (losses) on in investment trust recognized in other income, net (less than) | $ 1 | 1 |
UNS Energy | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Realized gain, portion shared with customers | 10.00% | |
Energy contracts subject to regulatory deferral | Derivative instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Regulatory assets | $ 57 | 87 |
Regulatory liability | 9 | 2 |
Energy contracts not subject to regulatory deferral | Not designated as hedging instrument | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unrealized (loss) gain recognized in revenue | (12) | 36 |
Foreign exchange contracts | Not designated as hedging instrument | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notional amount | 161 | |
Unrealized (loss) gains recognized in other income, net | (11) | 3 |
Interest rate swaps | Cash flow hedges | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Losses expected to be reclassified to earnings within the next twelve month | (3) | |
Interest rate swaps | UNS Energy | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notional amount | 16 | |
Total return swap | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notional amount | $ 41 | |
Total return swaps held | derivative | 3 | |
Unrealized gains (losses) on total return swaps (less than) | $ 1 | $ (1) |
Total return swap | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative terms | 1 year | |
Total return swap | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative terms | 3 years |
Fair Value of Financial Instr_4
Fair Value of Financial Instruments and Risk Management - Fair Value Hierarchy (Details) - Recurring - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Other investments | $ 155 | $ 78 |
Total assets | 212 | 132 |
Liabilities | ||
Total liabilities | (99) | (108) |
Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 41 | 21 |
Liabilities | ||
Liabilities | (89) | (106) |
Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 16 | 30 |
Liabilities | ||
Liabilities | (1) | (1) |
Foreign exchange contracts | ||
Assets | ||
Assets | 3 | |
Foreign exchange contracts, interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (9) | |
Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (1) | |
Level 1 | ||
Assets | ||
Other investments | 155 | 78 |
Total assets | 155 | 81 |
Liabilities | ||
Total liabilities | (8) | (1) |
Level 1 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | (1) |
Level 1 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | 0 |
Level 1 | Foreign exchange contracts | ||
Assets | ||
Assets | 3 | |
Level 1 | Foreign exchange contracts, interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (8) | |
Level 1 | Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | 0 | |
Level 2 | ||
Assets | ||
Other investments | 0 | 0 |
Total assets | 46 | 45 |
Liabilities | ||
Total liabilities | (88) | (104) |
Level 2 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 33 | 19 |
Liabilities | ||
Liabilities | (86) | (103) |
Level 2 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 13 | 26 |
Liabilities | ||
Liabilities | (1) | 0 |
Level 2 | Foreign exchange contracts | ||
Assets | ||
Assets | 0 | |
Level 2 | Foreign exchange contracts, interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (1) | |
Level 2 | Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (1) | |
Level 3 | ||
Assets | ||
Other investments | 0 | 0 |
Total assets | 11 | 6 |
Liabilities | ||
Total liabilities | (3) | (3) |
Level 3 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 8 | 2 |
Liabilities | ||
Liabilities | (3) | (2) |
Level 3 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 3 | 4 |
Liabilities | ||
Liabilities | 0 | (1) |
Level 3 | Foreign exchange contracts | ||
Assets | ||
Assets | 0 | |
Level 3 | Foreign exchange contracts, interest rate and total return swaps | ||
Liabilities | ||
Liabilities | $ 0 | |
Level 3 | Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | $ 0 |
Fair Value of Financial Instr_5
Fair Value of Financial Instruments and Risk Management - Reconciliation of Changes in Fair Value of Assets 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 [Roll Forward] | ||
Balance, beginning of year | $ 3 | $ 2 |
Realized gains (losses) | 14 | (13) |
Settlements | (9) | 12 |
Transfers of assets out of level 3 | 0 | (2) |
Transfers of liabilities out of level 3 | 0 | 4 |
Balance, end of year | $ 8 | $ 3 |
Fair Value of Financial Instr_6
Fair Value of Financial Instruments and Risk Management - Derivative Contracts Under Master Netting Agreements and Collateral Positions (Details) - Energy Contracts - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative assets | ||
Gross Amount Recognized on Balance Sheet | $ 57 | $ 51 |
Counterparty Netting of Energy Contracts | 28 | 17 |
Cash Collateral Received/Posted | 16 | 7 |
Net Amount | 13 | 27 |
Derivative liabilities | ||
Gross Amount Recognized on Balance Sheet | (90) | (107) |
Counterparty Netting of Energy Contracts | (28) | (17) |
Cash Collateral Received/Posted | 0 | 0 |
Net Amount | $ (62) | $ (90) |
Fair Value of Financial Instr_7
Fair Value of Financial Instruments and Risk Management - Volume of Derivative Activity (Details) kJ in Trillions | 12 Months Ended | |
Dec. 31, 2018GWhkJ | Dec. 31, 2017GWhkJ | |
Electricity swap contracts, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 774 | 1,291 |
Electricity power purchase contracts, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 651 | 761 |
Gas swap contracts, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | kJ | 203 | 216 |
Gas supply contract premiums, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | kJ | 266 | 219 |
Wholesale trading contracts, not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 1,440 | 2,387 |
Gas swap contracts, not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | kJ | 37 | 36 |
Fair Value of Financial Instr_8
Fair Value of Financial Instruments and Risk Management - Credit Risk (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Concentration Risk [Line Items] | ||
Derivative instruments in net liability positions | $ 75 | $ 57 |
Concentration of credit risk | Three customers | Revenue | ITC | ||
Concentration Risk [Line Items] | ||
Concentration risk percentage | 70.00% |
Fair Value of Financial Instr_9
Fair Value of Financial Instruments and Risk Management - Foreign Exchange Hedge (Details) - Foreign net investments - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Unhedged foreign net investments | $ 7,970 | $ 7,548 |
Designated as hedging instrument | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Long-term debt designated as an effective hedge | $ 3,441 | $ 3,385 |
Fair Value of Financial Inst_10
Fair Value of Financial Instruments and Risk Management - Financial Instruments Not Carried At Fair Value (Details) - CAD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Carrying Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion | $ 24,231 | $ 21,535 |
Level 2 | Estimated Fair Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion | $ 25,110 | $ 23,481 |
Variable Interest Entity (Detai
Variable Interest Entity (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Assets | |||
Cash and cash equivalents | $ 332 | $ 327 | $ 269 |
Accounts receivable and other current assets | 1,357 | 1,131 | |
PPE | 32,654 | 29,668 | |
Intangible assets | 1,200 | 1,081 | |
Total assets | 53,051 | 47,822 | |
Liabilities | |||
Accounts payable and other current liabilities | (2,289) | (2,053) | |
Other liabilities | (1,138) | (1,210) | |
Total liabilities | (34,595) | (31,073) | |
Revenue | 8,390 | 8,301 | |
Expenses | |||
Operating expenses | 2,287 | 2,250 | |
Depreciation and amortization | 1,243 | 1,179 | |
Finance charges | 974 | 914 | |
Net earnings | 1,286 | 1,125 | |
Capital expenditures | 3,218 | 3,024 | |
Dividends paid to non-controlling interests | $ 85 | 109 | |
Waneta Partnership | |||
Variable Interest Entity [Line Items] | |||
Controlling ownership interest (percent) | 51.00% | ||
Noncontrolling ownership (percent) | 49.00% | ||
Variable Interest Entity | Waneta Partnership | |||
Variable Interest Entity [Line Items] | |||
Controlling ownership interest (percent) | 51.00% | ||
Noncontrolling ownership (percent) | 49.00% | ||
Long-term contract for electric power, term | 40 years | ||
Assets | |||
Cash and cash equivalents | $ 15 | 16 | |
Accounts receivable and other current assets | 15 | 14 | |
PPE | 674 | 688 | |
Intangible assets | 30 | 30 | |
Total assets | 734 | 748 | |
Liabilities | |||
Accounts payable and other current liabilities | (6) | (28) | |
Other liabilities | (67) | (63) | |
Total liabilities | (73) | (91) | |
Net assets before partners' equity | 661 | 657 | |
Revenue | 94 | 93 | |
Expenses | |||
Operating expenses | 18 | 17 | |
Depreciation and amortization | 18 | 18 | |
Finance charges | 4 | 4 | |
Total operating expenses | 40 | 39 | |
Net earnings | 54 | 54 | |
Capital expenditures | 27 | 5 | |
Dividends paid to non-controlling interests | 35 | 34 | |
Advances from non-controlling interests | $ 11 | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Fiscal Year Maturity (Details) $ in Millions | Dec. 31, 2018CAD ($) |
Operating lease obligations: | |
Total | $ 51 |
Due within 1 year | 8 |
Due in year 2 | 6 |
Due in year 3 | 5 |
Due in year 4 | 4 |
Due in year 5 | 4 |
Due after 5 years | 24 |
Total | 24,034 |
Due within 1 year | 2,053 |
Due in year 2 | 1,842 |
Due in year 3 | 1,792 |
Due in year 4 | 1,516 |
Due in year 5 | 1,411 |
Due after 5 years | 15,420 |
Power | |
Purchase obligations: | |
Total | 2,438 |
Due within 1 year | 254 |
Due in year 2 | 191 |
Due in year 3 | 174 |
Due in year 4 | 170 |
Due in year 5 | 172 |
Due after 5 years | 1,477 |
Renewable power | |
Purchase obligations: | |
Total | 1,699 |
Due within 1 year | 110 |
Due in year 2 | 110 |
Due in year 3 | 109 |
Due in year 4 | 109 |
Due in year 5 | 108 |
Due after 5 years | 1,153 |
Gas | |
Purchase obligations: | |
Total | 1,348 |
Due within 1 year | 359 |
Due in year 2 | 290 |
Due in year 3 | 242 |
Due in year 4 | 202 |
Due in year 5 | 144 |
Due after 5 years | 111 |
Long-term contracts - UNS Energy | UNS Energy | |
Purchase obligations: | |
Total | 777 |
Due within 1 year | 176 |
Due in year 2 | 142 |
Due in year 3 | 92 |
Due in year 4 | 60 |
Due in year 5 | 46 |
Due after 5 years | 261 |
Renewable energy credit purchase agreement | |
Purchase obligations: | |
Total | 146 |
Due within 1 year | 24 |
Due in year 2 | 26 |
Due in year 3 | 18 |
Due in year 4 | 11 |
Due in year 5 | 11 |
Due after 5 years | 56 |
Interest obligations on long-term debt | |
Other commitments: | |
Total | 16,345 |
Due within 1 year | 994 |
Due in year 2 | 973 |
Due in year 3 | 950 |
Due in year 4 | 902 |
Due in year 5 | 870 |
Due after 5 years | 11,656 |
ITC easement agreement | ITC | |
Other commitments: | |
Total | 436 |
Due within 1 year | 14 |
Due in year 2 | 14 |
Due in year 3 | 14 |
Due in year 4 | 14 |
Due in year 5 | 14 |
Due after 5 years | 366 |
Debt collection agreement | Maritime Electric | |
Other commitments: | |
Total | 119 |
Due within 1 year | 3 |
Due in year 2 | 3 |
Due in year 3 | 3 |
Due in year 4 | 3 |
Due in year 5 | 3 |
Due after 5 years | 104 |
Purchase of Springerville Common Facilities | |
Other commitments: | |
Total | 93 |
Due within 1 year | 0 |
Due in year 2 | 0 |
Due in year 3 | 93 |
Due in year 4 | 0 |
Due in year 5 | 0 |
Due after 5 years | 0 |
Joint-use asset and shared service agreements | |
Other commitments: | |
Total | 52 |
Due within 1 year | 3 |
Due in year 2 | 3 |
Due in year 3 | 3 |
Due in year 4 | 3 |
Due in year 5 | 3 |
Due after 5 years | 37 |
Other | |
Other commitments: | |
Total | 530 |
Due within 1 year | 108 |
Due in year 2 | 84 |
Due in year 3 | 89 |
Due in year 4 | 38 |
Due in year 5 | 36 |
Due after 5 years | $ 175 |
Commitments and Contingencies_2
Commitments and Contingencies - Fiscal Year Maturity (Footnotes) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018CAD ($)GWhleaseagreement_renewalcontractMW | |
ITC | ITC easement agreement | |
Long-term Purchase Commitment [Line Items] | |
Number of agreement renewals | agreement_renewal | 10 |
Agreement renewal term | 50 years |
UNS Energy | Springerville Common Facilities | |
Long-term Purchase Commitment [Line Items] | |
Capital leases, undivided leased interest, percentage | 32.20% |
Number of leases | lease | 2 |
Power | |
Long-term Purchase Commitment [Line Items] | |
Purchase obligation | $ 2,438 |
Power | Maritime Electric | |
Long-term Purchase Commitment [Line Items] | |
Number of long-term take-or-pay contracts | contract | 2 |
Power | Maritime Electric | Nuclear Generating Station | |
Long-term Purchase Commitment [Line Items] | |
Share of plant output, percentage | 4.55% |
Power | Maritime Electric | Payment guarantee | |
Long-term Purchase Commitment [Line Items] | |
Purchase obligation | $ 771 |
Power | FortisOntario | |
Long-term Purchase Commitment [Line Items] | |
Purchase obligation | $ 705 |
Power | FortisOntario | Maximum | |
Long-term Purchase Commitment [Line Items] | |
Amount of volume required (in mw) | MW | 145 |
Power | FortisOntario | Minimum | |
Long-term Purchase Commitment [Line Items] | |
Volume of energy required to be purchased (in GWh) | GWh | 537 |
Power | FortisBC Energy | |
Long-term Purchase Commitment [Line Items] | |
Purchase obligation | $ 522 |
Power | FortisBC Electric | |
Long-term Purchase Commitment [Line Items] | |
Purchase obligation | $ 345 |
Long-term renewable PPA, term | 20 years |
Power | FortisBC Electric | Maximum | |
Long-term Purchase Commitment [Line Items] | |
Amount of volume required (in mw) | MW | 200 |
Volume of energy required to be purchased (in GWh) | GWh | 1,752 |
Renewable Power | |
Long-term Purchase Commitment [Line Items] | |
Purchase obligation | $ 1,699 |
Renewable Power | TEP and UNS Electric, Inc | |
Long-term Purchase Commitment [Line Items] | |
Purchase commitment, percentage | 100.00% |
Commitments and Contingencies_3
Commitments and Contingencies - Other Commitments (Details) $ in Millions | 12 Months Ended | 60 Months Ended | ||||
Dec. 31, 2019CAD ($) | Dec. 31, 2018CAD ($) | Dec. 31, 2017CAD ($) | Dec. 31, 2023CAD ($) | Dec. 31, 2014USD ($)project | Dec. 31, 2014CAD ($)project | |
Other Commitments [Line Items] | ||||||
Capital expenditures | $ 3,218,000,000 | $ 3,024,000,000 | ||||
CH Energy Group | ||||||
Other Commitments [Line Items] | ||||||
Number of high-voltage transmission projects | project | 5 | 5 | ||||
Investment in electric transmission projects | $ 1,700 | $ 2,300,000,000 | ||||
CH Energy Group | Payment guarantee | ||||||
Other Commitments [Line Items] | ||||||
Maximum commitment | $ 182 | $ 248,000,000 | ||||
Obligation under guarantee | 0 | |||||
FHI | Payment guarantee | Parental guarantee | ||||||
Other Commitments [Line Items] | ||||||
Maximum commitment | 77,000,000 | $ 80,000,000 | ||||
FHI and Fortis | Claim related to pipeline rights | ||||||
Other Commitments [Line Items] | ||||||
Contingency accrual | $ 0 | |||||
Forecast | ||||||
Other Commitments [Line Items] | ||||||
Capital expenditures | $ 3,700,000,000 | $ 17,300,000,000 |
Comparative Figures (Details)
Comparative Figures (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Borrowings under committed credit facilities | $ 5,666 | $ 6,461 |
Repayments under credit facilities | 5,523 | 7,480 |
Net change in short-term borrowings | $ 38 | (192) |
Correction | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Net repayments and borrowings under committed credit facilities | (365) | |
Borrowings under committed credit facilities | 4,376 | |
Repayments under credit facilities | 5,441 | |
Net change in short-term borrowings | $ 700 |