Cover page
Cover page | 12 Months Ended |
Dec. 31, 2020shares | |
Document Information [Line Items] | |
Entity Registrant Name | FORTIS INC. |
Entity Central Index Key | 0001666175 |
Current Fiscal Year End Date | --12-31 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2020 |
Document Fiscal Year Focus | 2020 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 466,770,392 |
Entity Current Reporting Status | Yes |
Entity Emerging Growth Company | false |
Document Registration Statement | false |
Document Annual Report | true |
Entity File Number | 001-37915 |
Entity Incorporation, State or Country Code | A4 |
Entity Primary SIC Number | 4911 |
Entity Tax Identification Number | 98-0352146 |
Entity Address, Address Line Two | Suite 1100 |
Entity Address, Address Line One | 5 Springdale Street |
Entity Address, Address Line Three | Fortis Place |
Entity Address, City or Town | St. John's |
Entity Address, State or Province | NL |
Entity Address, Postal Zip Code | A1E 0E4 |
Entity Address, Country | CA |
City Area Code | 709 |
Local Phone Number | 737-2800 |
Title of 12(b) Security | Common Shares, without par value |
Trading Symbol | FTS |
Security Exchange Name | NYSE |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Entity Interactive Data Current | Yes |
ICFR Auditor Attestation Flag | true |
Business Contact | |
Document Information [Line Items] | |
Contact Personnel Name | James R. Reid |
Entity Address, Address Line Two | CT Corporation System |
Entity Address, Address Line One | 28 Liberty Street |
Entity Address, City or Town | New York |
Entity Address, State or Province | NY |
Entity Address, Postal Zip Code | 10015 |
City Area Code | 212 |
Local Phone Number | 894-8940 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 | |
Current assets | |||
Cash and cash equivalents | $ 249 | $ 370 | |
Accounts receivable and other current assets (Note 6) | 1,369 | 1,297 | |
Prepaid expenses | 102 | 88 | |
Inventories (Note 7) | 422 | 394 | |
Regulatory assets (Note 8) | 470 | 425 | |
Total current assets | 2,612 | 2,574 | |
Other assets (Note 9) | 670 | 620 | |
Regulatory assets (Note 8) | 3,118 | 2,958 | |
Property, plant and equipment, net (Note 10) | 35,998 | 33,988 | |
Intangible assets, net (Note 11) | 1,291 | 1,260 | |
Goodwill (Note 12) | 11,792 | 12,004 | |
Total assets | 55,481 | 53,404 | |
Current liabilities | |||
Short-term borrowings (Note 14) | 132 | 512 | |
Accounts payable and other current liabilities (Note 13) | 2,321 | 2,402 | |
Regulatory liabilities (Note 8) | 441 | 572 | |
Current installments of long-term debt (Note 14) | 1,254 | 690 | |
Total current liabilities | 4,148 | 4,176 | |
Other liabilities (Note 16) | 1,599 | 1,446 | |
Regulatory liabilities (Note 8) | 2,662 | 2,786 | |
Deferred income taxes (Note 24) | 3,344 | 2,969 | |
Long-term debt (Note 14) | 23,113 | 21,501 | |
Finance leases (Note 15) | 331 | 413 | |
Total liabilities | 35,197 | 33,291 | |
Commitments and contingencies (Note 28) | |||
Equity | |||
Common shares (Note 17) | [1] | 13,819 | 13,645 |
Preference shares (Note 19) | 1,623 | 1,623 | |
Additional paid-in capital | 11 | 11 | |
Accumulated other comprehensive income (Note 20) | 34 | 336 | |
Retained earnings | 3,210 | 2,916 | |
Shareholders' equity | 18,697 | 18,531 | |
Non-controlling interests | 1,587 | 1,582 | |
Total equity | 20,284 | 20,113 | |
Total liabilities and equity | $ 55,481 | $ 53,404 | |
[1] | (1) No par value. Unlimited authorized shares. 466.8 million and 463.3 million issued and outstanding as at December 31, 2020 and 2019, respectively |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - shares shares in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Common stock, shares issued (in shares) | 466.8 | 463.3 |
Common stock, shares outstanding (in shares) | 466.8 | 463.3 |
Consolidated Statements of Earn
Consolidated Statements of Earnings - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Income Statement [Abstract] | ||
Revenue (Note 5) | $ 8,935 | $ 8,783 |
Expenses | ||
Energy supply costs | 2,562 | 2,520 |
Operating expenses | 2,437 | 2,452 |
Depreciation and amortization | 1,428 | 1,350 |
Total expenses | 6,427 | 6,322 |
Gain on disposition (Note 22) | 0 | 577 |
Operating income | 2,508 | 3,038 |
Other income, net (Note 23) | 154 | 138 |
Finance charges | 1,042 | 1,035 |
Earnings before income tax expense | 1,620 | 2,141 |
Income tax expense (Note 24) | 231 | 289 |
Net earnings | 1,389 | 1,852 |
Net earnings attributable to: | ||
Non-controlling interests | 115 | 130 |
Preference equity shareholders | 65 | 67 |
Common equity shareholders | 1,209 | 1,655 |
Net earnings | $ 1,389 | $ 1,852 |
Earnings per common share (Note 18) | ||
Basic (CAD per share) | $ 2.60 | $ 3.79 |
Diluted (CAD per share) | $ 2.60 | $ 3.78 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Comprehensive Income [Abstract] | ||
Net earnings | $ 1,389 | $ 1,852 |
Other comprehensive loss | ||
Unrealized foreign currency translation losses, net of hedging activities and income tax expense of $3 million and $13Â million, respectively | (311) | (660) |
Other, net of income tax recovery of $9 million and $5 million, respectively | (27) | (7) |
Other comprehensive loss | (338) | (667) |
Comprehensive income | 1,051 | 1,185 |
Comprehensive income attributable to: | ||
Non-controlling interests | 79 | 55 |
Preference equity shareholders | 65 | 67 |
Common equity shareholders | 907 | 1,063 |
Comprehensive income | $ 1,051 | $ 1,185 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Comprehensive Income [Abstract] | ||
Unrealized foreign currently translation, tax expense | $ 3 | $ 13 |
Other, tax recovery | $ 9 | $ 5 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Operating activities | ||
Net earnings | $ 1,389 | $ 1,852 |
Adjustments to reconcile net earnings to net cash provided by operating activities: | ||
Depreciation - property, plant and equipment | 1,282 | 1,199 |
Amortization - intangible assets | 131 | 125 |
Amortization - other | 15 | 26 |
Deferred income tax expense (Note 24) | 226 | 247 |
Equity component, allowance for funds used during construction (Note 23) | (78) | (74) |
Gain on disposition (Note 22) | 0 | (583) |
Other | 165 | 145 |
Change in long-term regulatory assets and liabilities | 5 | (106) |
Change in working capital (Note 26) | (434) | (168) |
Cash from operating activities | 2,701 | 2,663 |
Investing activities | ||
Capital expenditures - property, plant and equipment | (3,857) | (3,499) |
Capital expenditures - intangible assets | (182) | (221) |
Contributions in aid of construction | 68 | 102 |
Proceeds on disposition (Note 22) | 0 | 995 |
Other | (161) | (145) |
Cash used in investing activities | (4,132) | (2,768) |
Financing activities | ||
Proceeds from long-term debt, net of issuance costs (Note 14) | 3,470 | 937 |
Repayments of long-term debt, net of extinguishment costs, and finance leases | (1,251) | (1,676) |
Borrowings under committed credit facilities | 5,648 | 5,892 |
Repayments under committed credit facilities | (5,299) | (6,290) |
Net change in short-term borrowings | (413) | 472 |
Issue of common shares, net of costs, and dividends reinvested (Note 17) | 58 | 1,442 |
Dividends | ||
Common shares, net of dividends reinvested | (786) | (494) |
Preference shares | (65) | (67) |
Subsidiary dividends paid to non-controlling interests | (65) | (73) |
Other | 30 | 11 |
Cash from financing activities | 1,327 | 154 |
Effect of exchange rate changes on cash and cash equivalents | (17) | (26) |
Change in cash and cash equivalents | (121) | 23 |
Cash and change in cash associated with assets held for sale | 0 | 15 |
Cash and cash equivalents, beginning of year | 370 | 332 |
Cash and cash equivalents, end of year | $ 249 | $ 370 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) shares in Millions, $ in Millions | Total | Common Shares (Note 17) | Preference Shares (Note 19) | Additional Paid-In Capital | Accumulated Other Comprehensive Income (Loss) (Note 20) | Retained Earnings | Non-Controlling Interests |
Balance, beginning of period (shares) at Dec. 31, 2018 | 428.5 | ||||||
Balance, beginning of period at Dec. 31, 2018 | $ 18,456 | $ 11,889 | $ 1,623 | $ 11 | $ 928 | $ 2,082 | $ 1,923 |
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,852 | 1,722 | 130 | ||||
Other comprehensive loss | (667) | (592) | (75) | ||||
Common shares issued (shares) | 34.8 | ||||||
Common shares issued | 1,751 | $ 1,756 | (5) | ||||
Advances to non-controlling interests | (8) | (8) | |||||
Subsidiary dividends paid to non-controlling interests | (73) | (73) | |||||
Dividends declared on common shares | (821) | (821) | |||||
Dividends on preference shares | (67) | (67) | |||||
Disposition (Note 22) | (318) | (318) | |||||
Other | 8 | 5 | 3 | ||||
Balance, end of period (shares) at Dec. 31, 2019 | 463.3 | ||||||
Balance, end of period at Dec. 31, 2019 | 20,113 | $ 13,645 | 1,623 | 11 | 336 | 2,916 | 1,582 |
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,389 | 1,274 | 115 | ||||
Other comprehensive loss | (338) | (302) | (36) | ||||
Common shares issued (shares) | 3.5 | ||||||
Common shares issued | 171 | $ 174 | (3) | ||||
Advances to non-controlling interests | (13) | (13) | |||||
Subsidiary dividends paid to non-controlling interests | (65) | (65) | |||||
Dividends declared on common shares | (915) | (915) | |||||
Dividends on preference shares | (65) | (65) | |||||
Other | 7 | 3 | 4 | ||||
Balance, end of period (shares) at Dec. 31, 2020 | 466.8 | ||||||
Balance, end of period at Dec. 31, 2020 | $ 20,284 | $ 13,819 | $ 1,623 | $ 11 | $ 34 | $ 3,210 | $ 1,587 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Stockholders' Equity [Abstract] | ||
Dividends declared on common shares (CAD per share) | $ 1.965 | $ 1.855 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | DESCRIPTION OF BUSINESS Fortis Inc. ("Fortis" or the "Corporation") is a well-diversified North American regulated electric and gas utility holding company. Entities within the reporting segments that follow operate with substantial autonomy. Regulated Utilities ITC: ITC Investment Holdings Inc., ITC Holdings Corp. 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: 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 generating capacity of 3,233 megawatts ("MW"), including 54 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: CH Energy Group, Inc., which includes primarily 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 65 MW. FortisBC Energy: FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, provides 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: FortisBC Inc. is 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 five hydroelectric generating facilities in British Columbia that are owned by third parties. Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company, Limited ("Maritime Electric"); FortisOntario Inc. ("FortisOntario"); a 39% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Partnership"); 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 ("Belize Electricity"). 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 143 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 130 MW. FortisOntario consists of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario with a generating capacity of 5 MW. Wataynikaneyap Partnership is a partnership between 24 First Nations communities, Fortis and Algonquin Power & Utilities Corp. with a mandate to connect 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 consists 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. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize. Non-Regulated Energy Infrastructure: Long-term contracted generation assets in Belize and the Aitken Creek natural gas storage facility ("Aitken Creek") in British Columbia. Generation assets in Belize consist of three hydroelectric generating facilities with a combined generating capacity of 51 MW, held through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL"). The output is sold to Belize Electricity under 50-year power purchase agreements ("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. The long-term contracted generation assets in British Columbia, the Waneta Expansion hydroelectric generating facility ("Waneta Expansion"), were sold on April 16, 2019. Corporate and Other: Captures expenses and revenues not specifically related to any reportable segment and those business operations that are below the required threshold for segmented reporting, including net corporate expenses of Fortis. |
Regulation
Regulation | 12 Months Ended |
Dec. 31, 2020 | |
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 the 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"). PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term. 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. There can be varying degrees of regulatory lag between when costs are incurred and when they are reflected in customer rates. 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 8). Nature of Regulation Allowed Common Equity (%) Allowed ROE (1) (%) Regulatory Authority 2020 2019 Significant Features ITC (2) (3) Federal Energy Regulatory Commission ("FERC") 60.0 10.77 10.63 Cost-based formula rates, with annual true-up mechanism (4) Incentive adders TEP Arizona Corporation Commission ("ACC") (5) FERC (6) 50.0 9.75 9.75 COS regulation Historical test year Formula transmission rates 54.0 10.40 10.40 UNS Electric ACC 52.8 9.50 9.50 UNS Gas ACC 50.8 9.75 9.75 Central Hudson (7) New York State Public Service Commission ("PSC") 50.0 8.80 8.80 COS regulation FortisBC Energy British Columbia Utilities Commission ("BCUC") 38.5 8.75 8.75 COS regulation with formula components and incentives (8) FortisBC Electric BCUC 40.0 9.15 9.15 Future test year FortisAlberta Alberta Utilities Commission ("AUC") 37.0 8.50 8.50 PBR (9) Newfoundland Power Newfoundland and Labrador Board of Commissioners of Public Utilities 45.0 8.50 8.50 COS regulation Maritime Electric Island Regulatory and Appeals Commission 40.0 9.35 9.35 COS regulation FortisOntario (10) Ontario Energy Board 40.0 8.52-9.30 8.78-9.30 COS regulation with incentive mechanisms Caribbean Utilities (11) Utility Regulation and Competition Office N/A 6.75-8.75 7.50-9.50 COS regulation Rate-cap adjustment mechanism based on published consumer price indices FortisTCI (12) Government of the Turks and Caicos Islands N/A 15.00-17.50 15.00-17.50 COS regulation (1) ROA for Caribbean Utilities and FortisTCI (2) Includes the allowed common equity and base ROE plus incentive adders for ITCTransmission, METC, and ITC Midwest (3) Including incentive adders, the May 2020 FERC decision implies an all-in ROE for ITC's subsidiaries operating in the Midcontinent Independent System Operator ("MISO") region of 10.77%, up from 10.63% as set in the November 2019 decision. See "Significant Regulatory Developments" below (4) Annual true-up reflected in rates within a two-year period (5) Effective January 1, 2021, 53% allowed common equity and 9.15% ROE with 0.20% return on the fair value increment. See "COVID-19 Pandemic Impacts - Delayed and Postponed Regulatory Proceedings" below (6) Approved effective August 1, 2019, subject to refund following hearing and settlement procedures. As at December 31, 2020, $19 million (2019 - $5 million) has been reserved as a regulatory liability (7) Pursuant to a three-year settlement agreement arising from a 2017 general rate application, Central Hudson's rates reflect a capital structure of 48%, 49% and 50% common equity as of July 1, 2018, 2019 and 2020, respectively. See "COVID-19 Pandemic Impacts - Delayed and Postponed Regulatory Proceedings" below (8) Formula and incentives have been set through 2024. See "Significant Regulatory Developments" below (9) FortisAlberta is subject to PBR including mechanisms for flow-through costs and capital expenditures not otherwise recovered through customer rates. FortisAlberta's current PBR term expires as of December 31, 2022 (10) Two of FortisOntario's utilities follow COS regulation with incentive mechanisms, while the remaining utility is subject to a 35-year franchise agreement expiring in 2033 (11) Operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial 20-year period, expiring in April 2028, with a provision for automatic renewal. Its non-exclusive generation licence is for a 25-year term, expiring in November 2039 (12) Operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037 COVID-19 Pandemic Impacts The novel coronavirus ("COVID-19") pandemic resulted in several customer relief initiatives as well as the delay and postponement of several regulatory proceedings in 2020, as described below. The Corporation's significant regulatory proceedings, including TEP's general rate application as well as FortisAlberta's 2021 generic cost of capital ("GCOC") and Alberta Electric System Operator ("AESO") customer contribution proceedings, were concluded by the end of 2020. Customer Relief Initiatives UNS Energy Pursuant to the ACC's approval of the utility's customer relief initiatives, TEP refunded to customers approximately $11 million of collected demand side management funds in excess of program costs. In December 2020, the ACC enacted a bill credit and payment program for residential electric customers who are behind on their electric bills as a result of the COVID-19 pandemic, including automatic enrollment into an eight-month payment plan for qualified customers. TEP voluntarily created payment arrangements for commercial customers. Central Hudson In March 2020, as agreed with the PSC, Central Hudson postponed the collection in customer rates of approximately $4 million of deferred costs related mainly to environmental remediation until July 1, 2021. FortisBC Energy and FortisBC Electric In April 2020, pursuant to the BCUC's approval of the utilities' customer relief initiatives, FortisBC Energy and FortisBC Electric implemented three-month bill deferrals for certain customer classes, the repayment of which commenced in the third quarter of 2020. The BCUC also authorized the deferral of otherwise uncollectible revenue from customers, the recovery of which will be determined through a future rate filing once the financial impact of the pandemic is known. Delayed and Postponed Regulatory Proceedings UNS Energy General Rate Application: TEP filed a rate application in April 2019 based on a 2018 test year. In December 2020 the ACC issued a rate order including new customer rates effective January 1, 2021 ("2020 Rate Order"). Provisions of the 2020 Rate Order include: (i) an increase in non-fuel revenue of $77 million (US$58 million); (ii) an allowed ROE of 9.15%, with a 0.20% return on the fair value increment and a capital structure of 53% common equity; and (iii) a rate base of approximately $3.5 billion (US$2.7 billion) which includes post-test year investments in Gila River natural gas generation station Unit 2 and 10 natural gas reciprocating internal combustion engine units. Central Hudson 2020 Rates: In June 2020, the PSC approved Central Hudson's request to postpone scheduled electric and gas delivery rate increases, reflecting an increase in the equity component of its capital structure from 49% to 50%, from July 1, 2020 to October 1, 2020. The deferred revenue associated with the delay is being collected over the nine-month period to June 30, 2021. COVID-19 Proceeding: In June 2020, the PSC initiated a generic proceeding to identify and address the effects of the COVID-19 pandemic. The outcome of this proceeding and potential impacts, if any, are unknown at this time. FortisAlberta Generic Cost of Capital Proceeding: In December 2018, the AUC initiated a GCOC proceeding to consider a formula-based approach to setting the allowed ROE beginning in 2021 and whether any process changes were necessary for determining capital structure in years in which a ROE formula is in place. In October 2020, given the time that had passed since initiation of the proceeding and ongoing economic uncertainty, the AUC concluded the proceeding and set the ROE for 2021 at 8.5% using a capital structure of 37% common equity, consistent with 2020. In December 2020, the AUC initiated a new GCOC proceeding to establish the cost of capital parameters for 2022 and possibly one or more future years. This proceeding is expected to be ongoing throughout 2021. Other Electric Caribbean Utilities: In August 2020, the Utility Regulation and Competition Office approved the postponement of Caribbean Utilities' scheduled June 1, 2020 annual rate adjustment to January 1, 2021 to provide customer relief from the economic effects of the COVID-19 pandemic. The deferred revenue associated with the delay is being collected over a two-year period beginning January 2021. FortisTCI: In February 2020, the Government of the Turks and Caicos Islands approved a 6.8% average increase in FortisTCI's electricity rates, effective April 1, 2020, including the recovery of hurricane-related costs incurred in 2017. In March 2020, to provide customer relief from the economic effects of the COVID-19 pandemic, the effective date was postponed and new rates became effective July 22, 2020. FortisTCI sought regulatory approval to defer its incremental operating expenses associated with the COVID-19 pandemic. Approval was granted in December 2020 to allow the deferral of approximately $1.5 million in costs, to be amortized over the remaining 15-year life of FortisTCI's licence. Significant Regulatory Developments ITC ROE Complaints: In May 2020, FERC issued an order on the rehearing of its November 2019 decision on the MISO transmission owner ROE complaints and set the base ROE for the periods from November 2013 through February 2015 and from September 2016 onward at 10.02%, up to a maximum of 12.62% with incentive adders. This represents an increase from the base ROE of 9.88%, up to a maximum of 12.24% with incentive adders, determined in FERC's November 2019 decision. Including incentive adders, the May 2020 FERC decision implies an all-in ROE for ITC's subsidiaries operating in the MISO region of 10.77%, up from 10.63% as set in the November 2019 decision. Net regulatory liabilities of $6 million and $91 million were recorded at December 31, 2020 and 2019, respectively, reflecting: (i) the terms of the May 2020 and November 2019 decisions; and (ii) $42 million refunded to customers in 2020. The May 2020 FERC decision resulted in an increase in Fortis' net earnings of $29 million in 2020, including $27 million related to the reversal of liabilities established in prior periods (2019 - November 2019 FERC decision increased Fortis' net earnings by $63 million, including $83 million related to the reversal of liabilities established in prior periods). Review of Transmission Incentives Policy: In March 2020, FERC issued a notice of proposed rulemaking ("NOPR") that included a proposal to update its transmission incentives policy for transmission owners, including ITC, to grant incentives to projects based upon benefits to customers regarding reliability and cost savings through the reduction of transmission congestion. FERC proposed total ROE incentives of up to 250 basis points that would not be limited by the upper end of the base ROE zone of reasonableness. The NOPR also proposed, among other things, to eliminate the ROE adder for independent transmission ownership, and to increase the ROE adder for regional transmission owner participation. Comments from stakeholders, including ITC, were provided to FERC through July 2020. The outcome of these proceedings may impact future incentive adders that are included in transmission rates charged by transmission owners, including ITC. Central Hudson General Rate Application: In August 2020, Central Hudson filed a rate application with the PSC requesting an increase in electric and natural gas delivery revenue of $44 million and $19 million, respectively, effective July 1, 2021. An order from the PSC is expected in 2021. FortisBC Energy and FortisBC Electric Multi-Year Rate Plan Applications: In June 2020, the BCUC issued a decision on FortisBC Energy's and FortisBC Electric's multi-year rate plan applications for 2020 to 2024. The decision sets the rate-setting framework for the five-year period, including: (i) the level of operation and maintenance expense and growth capital to be included in customer rates, indexed for inflation less a fixed productivity adjustment factor; (ii) a forecast approach to sustainment capital; (iii) an innovation fund recognizing the need to accelerate investment in clean energy innovation; and (iv) a 50/50 sharing between customers and the utilities of variances from the allowed ROE. In the fourth quarter of 2020, the BCUC approved: (i) the January 1, 2020 delivery rate increase; and (ii) an increase in 2021 delivery rates, effective January 1, 2021, reflecting the terms of this decision. Generic Cost of Capital Proceeding: In January 2021, the BCUC issued a notice that a GCOC proceeding will be initiated in the second quarter of 2021 and will include a review of the common equity component of capital structure and the allowed ROE effective January 1, 2022. FortisAlberta 2018 Independent System Operator Tariff Application: In September 2019, the AUC issued a decision that addressed, among other things, a proposal to change how the AESO customer contribution policy ("ACCP") is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners ("TFOs"). The decision prevented any future investment by FortisAlberta under the policy and directed that unamortized customer contributions of approximately $400 million as at December 31, 2017, which form part of FortisAlberta's rate base, be transferred to the incumbent TFO in FortisAlberta's service area. In November 2020, the AUC issued a decision: (i) reversing the proposed changes to the ACCP resulting in FortisAlberta retaining its unamortized customer contributions; and (ii) directing a change in the depreciation rate for AESO contributions to reflect the parameters of the underlying transmission facilities. FortisAlberta has adjusted the estimated service life and the associated depreciation rate of the unamortized AESO contributions resulting in a decrease in depreciation expense and an associated decrease in revenue in 2020. The AUC initiated a new proceeding in November 2020 to consider whether the ACCP should be modified on a prospective basis. A decision is expected in the second quarter of 2021. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2020 | |
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 a controlled variable interest entity up to the date of its disposition on April 16, 2019 (Note 22). 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 Credit Losses Fortis and its subsidiaries recognize an allowance for credit losses (2019 - allowance for doubtful accounts) to reduce accounts receivable for amounts estimated to be uncollectible. The allowance for credit losses is estimated based on historical collection patterns, sales, and current and forecast economic and other conditions. 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: (i) 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; or (ii) obligations to provide future service that customers have paid for in advance. 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 8) 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. Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC for 2020 totalled $41 million (2019 - $40 million) and 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 AESO toward funding the construction of transmission facilities. Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulator, UNS Energy and Central Hudson recognize 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 2020 ranged from 0.9% to 39.8% (2019 - 0.9% to 35.0%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.5% for 2020 (2019 – 2.6%). The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows. 2020 2019 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 32 5-80 32 Gas 18-95 38 15-95 36 Transmission Electric 20-90 43 20-90 43 Gas 10-85 35 5-85 32 Generation 1-85 24 1-85 25 Other 2-70 14 3-70 14 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 33.0% for 2020 (2019 – 1.0% to 33.0%). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2020 2019 (years) Service Life Weighted Service Life Weighted Computer software 3-15 4 3-10 4 Land, transmission and water rights 43-90 56 43-90 58 Other 10-100 12 10-100 12 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. 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. Goodwill at each of the Corporation's 11 reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized. The Corporation performs a qualitative assessment on each reporting unit, and if it is determined that it is not likely that fair value is less than carrying value, then a quantitative estimate of fair value is not required. When a quantitative assessment is necessary, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market approach along with a reconciliation of the total estimated fair value of all the reporting units to the Corporation's market capitalization, is also performed and evaluated. 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 each subsidiary maintain 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 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 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 8). 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 8). Leases A right-of-use asset and lease liability is recognized for all leases with a lease term greater than 12 months. The right-of-use asset and liability are both measured at the present value of future lease payments, excluding variable payments that are based on usage or performance. Future lease payments include both lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which Fortis accounts for as a single lease component. The present value is calculated using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. Renewal options are included in the lease term when it is reasonably certain that the option will be exercised. Finance 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. Revenue Recognition 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. Energy sales are 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. 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 is 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. 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. DSUs, PSUs and RSUs issued pre-2020 represent cash-settled awards and RSUs issued in 2020 represent cash or share-settled awards, depending on settlement elections and share ownership requirements of the executive. 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, 2020 was $52.36 (2019 - $53.97). 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 accumulat ed other comprehensive income. The exchange rate as at December 31, 2020 was US$1.00=CA$1.27 ( 2019 – US$1.00=CA$1.30). 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=CA$1.34 for 2020 (2019 - US$1.00=CA$1.33). 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, PSU 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 recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8). 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 Fortis, ITC and UNS Energy use cash flow hedges, from time to time, 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 certain 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 of, 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 BECOL are not subject to income tax. Differences between the income tax expense or recovery recognized under US GAAP and 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 8). 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 $3.4 billion as at December 31, 2020 (2019 - $2.8 billion). 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, rights-of-way 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 16) 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. Accretion and depreciation expense are deferred as a regulatory asset or liability based on regulatory recovery of these costs. Actual settlement costs are recognized as a reduction in the accrued liability. Contingencies Fortis and its subsidiaries are subject to various legal proceedings and claims 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 periods of time. Actual outcomes may differ materially from the amounts recognized. New Accounting Policies Financial Instruments Effective January 1, 2020, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-13, Measurement of Credit Losses on Financial Instruments , which requires the use of reasonable and supportable forecasts in the estimation of credit losses and the recognition of expected losses upon initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. Adoption did not have a material impact on the consolidated financial statements and related disclosures. 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 Pronouncements The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board. Any ASUs not included in these consolidated financial statements were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements. |
Segmented Information
Segmented Information | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
Segmented Information | SEGMENTED INFORMATION General Fortis segments its business based on regulatory jurisdiction and service territory, as well as the information used by its CEO in deciding how to allocate resources. Segment performance is evaluated principally on net earnings attributable to common equity shareholders. 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 2020 or 2019. Inter-company balances, transactions and profit between non-regulated and regulated entities, which are not eliminated on consolidation, are summarized below. (in millions) 2020 2019 Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy $ 25 $ 23 Sale of capacity from the Waneta Expansion to FortisBC Electric (1) — 17 (1) Reflects amounts to the April 16, 2019 disposition of the Waneta Expansion (Note 22) As at December 31, 2020, accounts receivable included approximately $28 million due from Belize Electricity (2019 - $8 million). Fortis periodically provides short-term financing to its subsidiaries to support capital expenditures, acquisitions and seasonal working capital requirements. As at December 31, 2020, there were no material inter-segment loans outstanding (2019 - $279 million). The interest charged on inter-segment loans in 2020 and 2019 was not material. REGULATED NON-REGULATED Year ended Energy Inter- December 31, 2020 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 $ 1,744 $ 2,260 $ 953 $ 1,385 $ 596 $ 424 $ 1,485 $ 8,847 $ 88 $ — $ — $ 8,935 Energy supply costs — 847 232 468 — 119 893 2,559 3 — — 2,562 Operating expenses 438 627 503 341 148 117 194 2,368 30 39 — 2,437 Depreciation and amortization 295 330 90 237 212 61 183 1,408 16 4 — 1,428 Operating income 1,011 456 128 339 236 127 215 2,512 39 (43) — 2,508 Other income, net 40 40 31 8 2 5 10 136 5 13 — 154 Finance charges 324 125 48 142 104 72 77 892 — 150 — 1,042 Income tax expense 179 69 20 29 1 4 21 323 5 (97) — 231 Net earnings 548 302 91 176 133 56 127 1,433 39 (83) — 1,389 Non-controlling interests 99 — — 1 — — 15 115 — — — 115 Preference share dividends — — — — — — — — — 65 — 65 Net earnings attributable to common equity shareholders $ 449 $ 302 $ 91 $ 175 $ 133 $ 56 $ 112 $ 1,318 $ 39 $ (148) $ — $ 1,209 Goodwill $ 7,810 $ 1,758 $ 574 $ 913 $ 228 $ 235 $ 247 $ 11,765 $ 27 $ — $ — $ 11,792 Total assets 20,358 10,802 3,939 7,695 5,084 2,441 4,261 54,580 745 209 (53) 55,481 Capital expenditures 1,182 1,200 339 471 420 135 273 4,020 19 — — 4,039 Year ended December 31, 2019 (in millions) Revenue $ 1,761 $ 2,212 $ 917 $ 1,331 $ 598 $ 418 $ 1,467 $ 8,704 $ 82 $ — $ (3) $ 8,783 Energy supply costs — 814 254 438 — 121 890 2,517 3 — — 2,520 Operating expenses 489 650 451 333 145 107 188 2,363 36 56 (3) 2,452 Depreciation and amortization 270 297 79 235 214 62 171 1,328 20 2 — 1,350 Gain on disposition — — — — — — — — — 577 — 577 Operating income 1,002 451 133 325 239 128 218 2,496 23 519 — 3,038 Other income, net 37 28 17 16 2 4 2 106 2 30 — 138 Finance charges 290 130 46 136 104 72 77 855 — 180 — 1,035 Income tax expense 174 57 19 39 6 6 20 321 (1) (31) — 289 Net earnings 575 292 85 166 131 54 123 1,426 26 400 — 1,852 Non-controlling interests 104 — — 1 — — 17 122 8 — — 130 Preference share dividends — — — — — — — — — 67 — 67 Net earnings attributable to common equity shareholders $ 471 $ 292 $ 85 $ 165 $ 131 $ 54 $ 106 $ 1,304 $ 18 $ 333 $ — $ 1,655 Goodwill $ 7,970 $ 1,794 $ 586 $ 913 $ 228 $ 235 $ 251 $ 11,977 $ 27 $ — $ — $ 12,004 Total assets 19,799 10,205 3,726 7,305 4,831 2,328 4,185 52,379 711 641 (327) 53,404 Capital expenditures 1,148 915 317 463 423 106 295 3,667 28 25 — 3,720 |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | REVENUE (in millions) 2020 2019 Electric and gas revenue United States ITC $ 1,726 $ 1,697 UNS Energy 2,019 1,966 Central Hudson 941 894 Canada FortisBC Energy 1,336 1,289 FortisAlberta 580 576 FortisBC Electric 358 362 Newfoundland Power 707 671 Maritime Electric 215 209 FortisOntario 222 206 Caribbean Caribbean Utilities 238 270 FortisTCI 77 85 Total electric and gas revenue 8,419 8,225 Other services revenue (1) 325 374 Revenue from contracts with customers 8,744 8,599 Alternative revenue (2) 64 116 Other revenue 127 68 Total revenue $ 8,935 $ 8,783 (1) Includes $227 million and $273 million from regulated operations for 2020 and 2019, respectively (2) Includes a $40 million and $91 million base ROE adjustment associated with the May 2020 and November 2 019 FERC decisions, respectively (Notes 2 and 8) 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 including the flow through of commodity costs. Other services revenue includes: (i) management fee revenue at UNS Energy for the operation of Springerville Units 3 and 4; (ii) revenue from storage optimization activities at Aitken Creek; and (iii) 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. The significant alternative revenue programs of Fortis' utilities 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 8). 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 2% 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. FortisBC Energy and FortisBC Electric have an earnings sharing mechanism that provides for a 50/50 sharing of variances from the allowed ROE in 2020 (2019 - variances from formula-driven operation and maintenance expenses and capital expenditures). This mechanism is in place until the expiry of the current multi-year rate plan for 2020 to 2024. Additionally, variances between forecast and actual customer-use rates and industrial and other customer revenue are captured in a revenue stabilization account and a flow-through deferral account to be refunded to, or received from, customers in rates within two years. Other Revenue Other revenue primarily includes gains or losses on energy contract derivatives and regulatory deferrals at FortisBC Energy and FortisBC Electric reflecting cost recovery variances from forecast. |
Accounts Receivable and Other C
Accounts Receivable and Other Current Assets | 12 Months Ended |
Dec. 31, 2020 | |
Receivables [Abstract] | |
Accounts Receivable and Other Current Assets | ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS (in millions) 2020 2019 Trade accounts receivable $ 595 $ 504 Unbilled accounts receivable 571 601 Allowance for credit losses (1) (64) (35) 1,102 1,070 Income tax receivable 72 35 Other (2) 195 192 $ 1,369 $ 1,297 (1) Allowance for doubtful accounts for 2019 (2) Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 27) Allowance for Credit Losses The allowance for credit losses balance changed during 2020 as follows. (in millions) 2020 Balance, beginning of year $ (35) Credit loss expensed (36) Credit loss deferred (Note 2) (6) Write-offs, net of recoveries 14 Foreign exchange (1) Balance, end of year $ (64) The allowance for doubtful accounts balance changed during 2019 as follows. (in millions) 2019 Balance, beginning of year $ (33) Bad debt expensed (21) Write-offs, net of recoveries 18 Foreign exchange 1 Balance, end of year $ (35) |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2020 | |
Inventory Disclosure [Abstract] | |
Inventories | INVENTORIES (in millions) 2020 2019 Materials and supplies $ 297 $ 294 Gas and fuel in storage 101 69 Coal inventory 24 31 $ 422 $ 394 |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | REGULATORY ASSETS AND LIABILITIES (in millions ) 2020 2019 Regulatory assets Deferred income taxes (Notes 3 and 24) $ 1,697 $ 1,556 Employee future benefits (Notes 3 and 25) 588 530 Deferred energy management costs (1) 334 279 Rate stabilization and related accounts (2) 213 208 Deferred lease costs (3) 122 116 Manufactured gas plant site remediation deferral (Note 16) 107 81 Derivatives (Notes 3 and 27) 73 119 Generation early retirement costs (4) 55 88 Other regulatory assets (5) 399 406 Total regulatory assets 3,588 3,383 Less: Current portion (470) (425) Long-term regulatory assets $ 3,118 $ 2,958 Regulatory liabilities Deferred income taxes (Notes 3 and 24) $ 1,361 $ 1,440 Asset removal cost provision (Note 3) 1,206 1,187 Rate stabilization and related accounts (2) 104 166 Renewable energy surcharge (6) 100 94 Energy efficiency liability (7) 83 101 Employee future benefits (Notes 3 and 25) 43 45 Electric and gas moderator account (8) 28 45 ROE complaints liability (Note 2) 16 91 Other regulatory liabilities (5) 162 189 Total regulatory liabilities 3,103 3,358 Less: Current portion (441) (572) Long-term regulatory liabilities $ 2,662 $ 2,786 (1) 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 two to 10 years. (2) 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 of 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 5). (3) Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under the 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. (4) Generation Early Retirement Costs: TEP and the co-owners of Navajo Generating Station ("Navajo") retired Navajo in 2019, with related decommissioning activities continuing through 2054. TEP also retired Sundt Generating Facility Units 1 and 2 ("Sundt") in 2019. The ACC approved the recovery of the retirement costs of Navajo and Sundt over a 10-year period as part of the 2020 Rate Order (Note 2). (5) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million. (6) 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 a 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 ("RECs"). 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 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount. (7) 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. (8) 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 $1,678 million and $1,510 million as at December 31, 2020 and 2019, 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. |
Other Assets
Other Assets | 12 Months Ended |
Dec. 31, 2020 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | OTHER ASSETS (in millions) 2020 2019 Supplemental Executive Retirement Plan ("SERP") $ 155 $ 145 Renewable Energy Credits (Note 8) 106 99 Equity investment - Belize Electricity 80 71 Employee future benefits (Note 25) 66 63 Other investments 66 43 Operating leases (Note 15) 40 46 Deferred compensation plan 36 30 Equity Investment - Wataynikaneyap Partnership 12 12 Other (1) 109 111 $ 670 $ 620 (1) Includes the fair value of derivatives (Note 27) ITC, UNS Energy and Central Hudson provide additional post-employment benefits through SERPs and deferred compensation plans for directors and officers. The assets held to support these plans are reported separately from the related liabilities (Note 16). 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 27). |
Property, Plant And Equipment
Property, Plant And Equipment | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Property, Plant And Equipment | PROPERTY, PLANT AND EQUIPMENT (in millions) Cost Accumulated Depreciation Net Book Value 2020 Distribution Electric $ 11,921 $ (3,223) $ 8,698 Gas 5,546 (1,422) 4,124 Transmission Electric 15,888 (3,413) 12,475 Gas 2,360 (719) 1,641 Generation 6,441 (2,550) 3,891 Other 4,178 (1,347) 2,831 Assets under construction 2,012 — 2,012 Land 326 — 326 $ 48,672 $ (12,674) $ 35,998 2019 Distribution Electric $ 11,396 $ (3,125) $ 8,271 Gas 5,277 (1,330) 3,947 Transmission Electric 15,207 (3,293) 11,914 Gas 2,267 (681) 1,586 Generation 6,380 (2,472) 3,908 Other 4,042 (1,327) 2,715 Assets under construction 1,329 — 1,329 Land 318 — 318 $ 46,216 $ (12,228) $ 33,988 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, wind resources and other related equipment. Other assets include buildings, equipment, vehicles, inventory, information technology assets and Aitken Creek. As at December 31, 2020, assets under construction were primarily associated with ongoing transmission projects at ITC and the addition of wind-powered electric generating capacity at UNS Energy. The cost of PPE under finance lease as at December 31, 2020 was $322 million (2019 - $514 million) and related accumulated depreciation was $111 million (2019 - $206 million) (Note 15). 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, 2020, interests in jointly owned facilities consisted of the following. Ownership Accumulated Net Book (in millions, except as noted) (%) Cost Depreciation Value Transmission Facilities 1.0-80.0 $ 980 $ (381) $ 599 Springerville Common Facilities (1) 86.0 505 (251) 254 San Juan Unit 1 ("San Juan") 50.0 370 (304) 66 Springerville Coal Handling Facilities 83.0 268 (121) 147 Four Corners Units 4 and 5 ("Four Corners") 7.0 235 (97) 138 Gila River Common Facilities 50.0 108 (36) 72 Luna Energy Facility ("Luna") 33.3 74 (2) 72 $ 2,540 $ (1,192) $ 1,348 |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2020 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | INTANGIBLE ASSETS Accumulated Net Book (in millions ) Cost Amortization Value 2020 Computer software $ 932 $ (524) $ 408 Land, transmission and water rights 898 (142) 756 Other 114 (64) 50 Assets under construction 77 — 77 $ 2,021 $ (730) $ 1,291 2019 Computer software $ 946 $ (576) $ 370 Land, transmission and water rights 890 (122) 768 Other 115 (61) 54 Assets under construction 68 — 68 $ 2,019 $ (759) $ 1,260 Included in the cost of land, transmission and water rights as at December 31, 2020 was $136 million (2019 - $133 million) not subject to amortization. Amortization expense was $131 million for 2020 (2019 - $125 million). Amortization is estimated to average approximately $81 million for each of the next five years. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2020 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | GOODWILL (in millions) 2020 2019 Balance, beginning of year $ 12,004 $ 12,530 Foreign currency translation impacts (1) (212) (526) Balance, end of year $ 11,792 $ 12,004 (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 2020 or 2019. |
Accounts Payable and Other Curr
Accounts Payable and Other Current Liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Other Current Liabilities | ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES (in millions) 2020 2019 Trade accounts payable $ 707 $ 754 Employee compensation and benefits payable 248 229 Dividends payable 241 228 Accrued taxes other than income taxes 224 223 Interest payable 215 212 Customer and other deposits 214 226 Gas and fuel cost payable 188 225 Fair value of derivatives (Note 27) 56 83 Manufactured gas plant site remediation (Note 16) 31 31 Employee future benefits (Note 25) 26 24 Other 171 167 $ 2,321 $ 2,402 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | LONG-TERM DEBT (in millions ) Maturity Date 2020 2019 ITC Secured US First Mortgage Bonds - 4.31% weighted average fixed rate (2019 - 4.46%) 2024-2055 $ 2,755 $ 2,624 Secured US Senior Notes - 4.00% weighted average fixed rate (2019 - 4.26%) 2040-2055 923 747 Unsecured US Senior Notes - 3.61% weighted average fixed rate (2019 - 3.79%) 2022-2043 4,136 3,312 Unsecured US Shareholder Note - 6.00% fixed rate (2019 - 6.00%) 2028 253 258 Unsecured US Term Loan Credit Agreement - 2.35% weighted average fixed rate n/a — 260 UNS Energy Unsecured US Tax-Exempt Bonds - 4.34% weighted average fixed and variable rate (2019 - 4.64%) 2029-2030 362 603 Unsecured US Fixed Rate Notes - 3.86% weighted average fixed rate (2019 - 4.38%) 2021-2050 2,704 1,851 Central Hudson Unsecured US Promissory Notes - 3.94% weighted average fixed and variable rate (2019 - 4.27%) 2021-2060 1,078 986 FortisBC Energy Unsecured Debentures - 4.72% weighted average fixed rate (2019 - 4.87%) 2026-2050 2,995 2,795 FortisAlberta Unsecured Debentures - 4.49% weighted average fixed rate (2019 - 4.64%) 2024-2052 2,360 2,185 FortisBC Electric Secured Debentures - 8.80% fixed rate (2019 - 8.80%) 2023 25 25 Unsecured Debentures - 4.87% weighted average fixed rate (2019 - 5.05%) 2021-2050 785 710 Other Electric Secured First Mortgage Sinking Fund Bonds - 5.61% weighted average fixed rate (2019 - 6.14%) 2022-2060 634 571 Secured First Mortgage Bonds - 5.66% weighted average fixed rate (2019 - 5.66%) 2025-2061 220 220 Unsecured Senior Notes - 4.45% weighted average fixed rate (2019 - 4.45%) 2041-2048 152 152 Unsecured US Senior Loan Notes and Bonds - 4.41% weighted average fixed and variable rate (2019 - 4.53%) 2022-2049 648 645 Corporate and Other Unsecured US Senior Notes and Promissory Notes - 3.81% weighted average fixed rate (2019 - 3.80%) 2021-2044 2,685 2,903 Unsecured Debentures - 6.50% fixed rate (2019 - 6.50%) 2039 200 200 Unsecured Senior Notes - 2.85% fixed rate (2019 - 2.85%) 2023 500 500 Long-term classification of credit facility borrowings 980 640 Fair value adjustment - ITC acquisition 119 133 Total long-term debt (Note 27) 24,514 22,320 Less: Deferred financing costs and debt discounts (147) (129) Less: Current installments of long-term debt (1,254) (690) $ 23,113 $ 21,501 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 agreements have covenants that provide that the Corporation shall not declare, pay or make any dividends or any other restricted payments if, immediately thereafter, its consolidated debt to consolidated capitalization ratio would exceed 65%. Long-Term Debt Issuances (in millions, except as noted) Month Issued Interest Rate (%) Maturity Amount ($) Use of Proceeds ITC Unsecured term loan credit agreement January (1) 2021 US 75 (2)(3) Unsecured term loan credit agreement (4) January (5) 2021 US 200 (4) Unsecured senior notes May 2.95 2030 US 700 (2)(3)(6) First mortgage bonds July 3.13 2051 US 180 (2)(3)(7) Secured senior notes October 3.02 2055 US 150 (2)(3)(7)(8) UNS Energy Unsecured senior notes April 4.00 2050 US 350 (2)(3) Unsecured senior notes August 1.50 2030 US 300 (7) Unsecured senior notes September 2.17 2032 US 50 (2)(3) Central Hudson Unsecured senior notes May 3.42 2050 US 30 (3) Unsecured senior notes July 3.62 2060 US 30 (3)(7) Unsecured senior notes September 2.03 2030 US 40 (8) Unsecured senior notes November 2.03 2030 US 30 (3)(7) FortisBC Energy Unsecured debentures July 2.54 2050 200 (7) FortisAlberta Unsecured senior debentures December 2.63 2051 175 (2) FortisBC Electric Unsecured debentures May 3.12 2050 75 (2) Newfoundland Power First mortgage sinking fund bonds April 3.61 2060 100 (2)(3) FortisTCI Unsecured senior notes June/October 5.30 2035 US 30 (7)(8) Unsecured senior notes October/December 3.25 2030 US 10 (3) (1) Floating rate of a one-month LIBOR plus a spread of 0.45% (2) Repay credit facility borrowings (3) General corporate purposes (4) Maximum amount of borrowings under this agreement of US$400 million has been drawn; current period borrowings were used to repay an outstanding commercial paper balance. (5) Floating rate of a two-month LIBOR plus a spread of 0.60% (6) Early redemption of unsecured term loan borrowing of US$400 million (7) Finance capital expenditures (8) Repay maturing long-term debt 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. (in millions) Total 2021 $ 1,254 2022 823 2023 1,786 2024 1,088 2025 484 Thereafter 19,079 $ 24,514 In December 2020 Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $2.0 billion. As at December 31, 2020, $2.0 billion remained available under the short-form base shelf prospectus. Credit Facilities (in millions) Regulated Corporate 2020 2019 Total credit facilities $ 3,700 $ 1,881 $ 5,581 $ 5,590 Credit facilities utilized: Short-term borrowings (1) (132) — (132) (512) Long-term debt (including current portion) (2) (714) (266) (980) (640) Letters of credit outstanding (77) (53) (130) (114) Credit facilities unutilized $ 2,777 $ 1,562 $ 4,339 $ 4,324 (1) The weighted average interest rate was approximately 0.8% (2019 - 3.2%). (2) The weighted average interest rate was approximately 0.9% (2019 - 2.4% ) . The current portion was $651 million (2019 - $252 million). Credit facilities are syndicated primarily with large banks in Canada and the US, with no one bank holding more than approximately 25% of the total facilities. Approximately $5.3 billion of the total credit facilities are committed facilities with maturities ranging from 2021 through 2025. Consolidated credit facilities of approximately $5.6 billion as at December 31, 2020 are itemized below. (in millions) Amount ($) Maturity Unsecured committed revolving credit facilities Regulated utilities ITC (1) US 900 October 2023 UNS Energy US 500 October 2022 Central Hudson US 200 March 2025 FortisBC Energy 700 August 2024 FortisAlberta 250 August 2024 FortisBC Electric 150 April 2024 Other Electric 190 (2) Other Electric US 70 January 2025 Corporate and Other 1,850 (3) Other facilities Regulated utilities Central Hudson - uncommitted credit facility US 30 n/a FortisBC Energy - uncommitted credit facility 55 March 2022 FortisBC Electric - unsecured demand overdraft facility 10 n/a Other Electric - unsecured demand facilities 20 n/a Other Electric - unsecured demand facility and emergency standby loan US 60 June 2021 Corporate and Other - unsecured non-revolving facility 30 n/a (1) ITC also has a US$400 million commercial paper program, under which US$67 million was outstanding as at December 31, 2020, as reported in short-term borrowings. (2) $40 million in June 2021, $50 million in February 2022 and $100 million in August 2024 (3) $500 million in April 2021, $50 million in April 2022 and $1.3 billion in July 2024 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Leases | LEASES The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 21 years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises. The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 35 years. Leases were presented on the consolidated balance sheets as follows. (in millions) 2020 2019 Operating leases Other assets $ 40 $ 46 Accounts payable and other current liabilities (7) (8) Other liabilities (33) (38) Finance leases (1) (2) Regulatory assets $ 122 $ 116 PPE, net 211 308 Accounts payable and other current liabilities (2) (24) Finance leases (331) (413) (1) FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates to the use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, which includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the capital cost of the BTS, and related variable operating costs. (2) In December 2020 TEP purchased a 32.2% undivided interest in the Springerville Common Facilities, which had previously been leased (Note 10). The components of lease expense were as follows. (in millions) 2020 2019 Operating lease cost $ 10 $ 10 Finance lease cost: Amortization 14 17 Interest 34 48 Variable lease cost 20 39 Total lease cost $ 78 $ 114 As at December 31, 2020, the present value of minimum lease payments was as follows. (in millions) Operating Leases Finance Total 2021 $ 8 $ 33 $ 41 2022 7 34 41 2023 6 34 40 2024 4 34 38 2025 3 34 37 Thereafter 22 1,056 1,078 50 1,225 1,275 Less: Imputed interest (10) (892) (902) Total lease obligations 40 333 373 Less: Current installments (7) (2) (9) $ 33 $ 331 $ 364 Supplemental lease information was as follows. (in millions, except as noted) 2020 2019 Weighted average remaining lease term (years) Operating leases 10 10 Finance leases 35 27 Weighted average discount rate (%) Operating leases 4.0 4.1 Finance leases 5.1 4.8 Cash payments related to lease liabilities Operating cash flows used for operating leases $ (10) $ (10) Operating cash flows used for finance leases (2) (47) Financing cash flows used for finance leases (25) (16) Investing cash flows used for finance leases (87) (212) See Note 26 for non-cash transactions that resulted in right-of-use assets obtained in exchange for new lease liabilities. |
Leases | LEASES The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 21 years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises. The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 35 years. Leases were presented on the consolidated balance sheets as follows. (in millions) 2020 2019 Operating leases Other assets $ 40 $ 46 Accounts payable and other current liabilities (7) (8) Other liabilities (33) (38) Finance leases (1) (2) Regulatory assets $ 122 $ 116 PPE, net 211 308 Accounts payable and other current liabilities (2) (24) Finance leases (331) (413) (1) FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates to the use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, which includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the capital cost of the BTS, and related variable operating costs. (2) In December 2020 TEP purchased a 32.2% undivided interest in the Springerville Common Facilities, which had previously been leased (Note 10). The components of lease expense were as follows. (in millions) 2020 2019 Operating lease cost $ 10 $ 10 Finance lease cost: Amortization 14 17 Interest 34 48 Variable lease cost 20 39 Total lease cost $ 78 $ 114 As at December 31, 2020, the present value of minimum lease payments was as follows. (in millions) Operating Leases Finance Total 2021 $ 8 $ 33 $ 41 2022 7 34 41 2023 6 34 40 2024 4 34 38 2025 3 34 37 Thereafter 22 1,056 1,078 50 1,225 1,275 Less: Imputed interest (10) (892) (902) Total lease obligations 40 333 373 Less: Current installments (7) (2) (9) $ 33 $ 331 $ 364 Supplemental lease information was as follows. (in millions, except as noted) 2020 2019 Weighted average remaining lease term (years) Operating leases 10 10 Finance leases 35 27 Weighted average discount rate (%) Operating leases 4.0 4.1 Finance leases 5.1 4.8 Cash payments related to lease liabilities Operating cash flows used for operating leases $ (10) $ (10) Operating cash flows used for finance leases (2) (47) Financing cash flows used for finance leases (25) (16) Investing cash flows used for finance leases (87) (212) See Note 26 for non-cash transactions that resulted in right-of-use assets obtained in exchange for new lease liabilities. |
Other Liabilities
Other Liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Other Liabilities Disclosure [Abstract] | |
Other Liabilities | OTHER LIABILITIES (in millions) 2020 2019 Employee future benefits (Note 25) $ 905 $ 832 Customer and other deposits 132 70 AROs (Note 3) 130 148 Stock-based compensation plans (Note 21) 86 83 Manufactured gas plant site remediation (1) 69 48 Fair value of derivatives (Note 27) 50 68 Mine reclamation obligations (2) 47 43 Retail energy contract (3) 46 — Deferred compensation plan (Note 9) 43 33 Operating leases 33 38 Other 58 83 $ 1,599 $ 1,446 (1) Environmental regulations require Central Hudson to investigate sites at which it 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, 2020, an obligation of $96 million was recognized, including a current portion of $27 million recognized in accounts payable and other current liabilities (Note 13). 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 8). (2) TEP pays ongoing reclamation costs related to two 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 $61 million upon expiry of the coal agreements between 2022 and 2031. The present value of the estimated future liability is shown in the table above. (3) FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment in 2020 which will be amortized to earnings over the life of the agreement. |
Common Shares
Common Shares | 12 Months Ended |
Dec. 31, 2020 | |
Equity [Abstract] | |
Common Shares | COMMON SHARES During 2019 the Corporation issued approximately 4.1 million common shares under its at-the-market common equity program at an average price of $52.16 per share. The gross proceeds of $212 million ($209 million net of commissions) were used primarily to fund capital expenditures. Also during 2019 the Corporation issued approximately 22.8 million common shares representing gross proceeds of $1,190 million ($1,167 million net of commissions) at a price of $52.15 per share. The net proceeds were used to redeem US$500 million of its outstanding 2.10% unsecured notes due on October 4, 2021, to repay credit facility borrowings, and for general corporate purposes. |
Earnings Per Common Share
Earnings Per Common Share | 12 Months Ended |
Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |
Earnings Per Common Share | EARNINGS PER COMMON SHARE Diluted earnings per common share ("EPS") was calculated using the treasury stock method for options. 2020 2019 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares EPS Shareholders Shares EPS ($ millions) (# millions) ($) ($ millions) (# millions) ($) Basic EPS $ 1,209 464.8 $ 2.60 $ 1,655 436.8 $ 3.79 Potential dilutive effect of stock options — 0.6 — — 0.7 — Diluted EPS $ 1,209 465.4 $ 2.60 $ 1,655 437.5 $ 3.78 |
Preference Shares
Preference Shares | 12 Months Ended |
Dec. 31, 2020 | |
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 2020 2019 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 7,665 188 7,025 172 Series I 2,335 57 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. 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 — Currently Redeemable 25.00 — Series J (3) 4.75 1.1875 — Currently Redeemable 25.25 — Fixed rate reset (4) (5) Series G 5.25 1.0983 2.13 September 1, 2023 25.00 — Series H (6) 4.25 0.4588 1.45 June 1, 2025 25.00 Series I Series K 4.00 0.9823 2.05 March 1, 2024 25.00 Series L Series M 4.10 0.9783 2.48 December 1, 2024 25.00 Series N Floating rate reset (5) (7) Series I 2.10 — 1.45 June 1, 2025 25.00 Series H Series L — — — — — Series K Series N — — — — — 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 are redeemable as of December 1, 2021 and thereafter at $25.00 per share. (4) On the redemption and/or conversion option date, and on 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 H was reset from $0.6250 to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025. (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 June 1, 2020, 267,341 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I, and 907,577 First Preference Shares, Series I were converted on a one-for-one basis into First Preference Shares, Series H. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2020 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income | ACCUMULATED OTHER COMPREHENSIVE INCOME (in millions) Opening Balance Net Change Ending Balance 2020 Unrealized foreign currency translation gains (losses) Net investments in foreign operations $ 713 $ (336) $ 377 Hedges of net investments in foreign operations (359) 60 (299) Income tax expense (3) (3) (6) 351 (279) 72 Other Cash flow hedges (Note 27) 17 (21) (4) Unrealized employee future benefits losses (Note 25) (38) (11) (49) Income tax recovery 6 9 15 (15) (23) (38) Accumulated other comprehensive income $ 336 $ (302) $ 34 2019 Unrealized foreign currency translation gains (losses) Net investments in foreign operations $ 1,470 $ (757) $ 713 Hedges of net investments in foreign operations (544) 185 (359) Income tax recovery (expense) 10 (13) (3) 936 (585) 351 Other Cash flow hedges (Note 27) 11 6 17 Unrealized employee future benefits losses (Note 25) (20) (18) (38) Income tax recovery 1 5 6 (8) (7) (15) Accumulated other comprehensive income $ 928 $ (592) $ 336 |
Stock-based Compensation Plans
Stock-based Compensation Plans | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [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 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 2020 and 2019. 2020 2019 Options granted (in thousands) 686 852 Exercise price ($) (1) 58.40 47.57 Grant date fair value ($) 4.20 3.70 Valuation assumptions: Dividend yield (%) (2) 3.7 3.8 Expected volatility (%) (3) 15.8 15.2 Risk-free interest rate (%) (4) 1.2 1.8 Weighted average expected life (years) (5) 5.2 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 2020. Total Options Non-vested Options (1) (in thousands, except as noted) Number of Options Weighted Average Number of Options Weighted Average Options outstanding, beginning of year 3,418 $ 41.18 1,910 $ 3.43 Granted 686 $ 58.40 686 $ 4.20 Exercised (825) $ 39.21 n/a n/a Vested n/a n/a (807) $ 3.25 Cancelled/Forfeited (17) $ 50.02 (17) $ 3.79 Options outstanding, end of year 3,262 $ 45.26 1,772 $ 3.81 Options vested, end of year (2) 1,490 $ 39.40 (1) As at December 31, 2020, there was $7 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, 2020, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $19 million. The following table summarizes additional stock option information. (in millions) 2020 2019 Stock options exercised: Cash received for exercise price $ 32 $ 51 Intrinsic value realized by employees 15 22 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. 2020 2019 Number of units (in thousands) Beginning of year 165 177 Granted 25 29 Notional dividends reinvested 6 6 Paid out (49) (47) End of year 147 165 The accrued liability has been recognized at the respective December 31st VWAP (Note 3) and included in long-term other liabilities (Note 16). The accrued liability, compensation expense and cash payout were not material for 2020 or 2019. 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, 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 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. 2020 2019 Number of units (in thousands) Beginning of year 2,118 1,763 Granted 586 690 Notional dividends reinvested 71 73 Paid out (735) (357) Cancelled/forfeited (64) (51) End of year 1,976 2,118 Additional information (in millions) Compensation expense recognized $ 58 $ 74 Compensation expense unrecognized (1) 32 35 Cash payout 54 16 Accrued liability as at December 31 (2) 108 106 Aggregate intrinsic value as at December 31 (3) 140 141 (1) Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years (2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16) (3) 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 or, beginning with the 2020 grant, common shares of the Corporation. RSUs issued in 2020 may be settled in cash, common shares, or an equal proportion of cash and common shares depending on an executives' settlement election and whether their share ownership requirements have been met. The following table summarizes information related to RSUs. 2020 2019 Number of units (in thousands) Beginning of year 1,050 717 Granted 356 429 Notional dividends reinvested 37 35 Paid out (355) (92) Cancelled/forfeited (40) (39) End of year 1,048 1,050 Additional information (in millions) Compensation expense recognized $ 20 $ 24 Compensation expense unrecognized (1) 15 17 Cash payout 19 4 Accrued liability as at December 31 (2) 39 39 Aggregate intrinsic value as at December 31 (3) 54 56 (1) Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years (2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16) (3) Relates to outstanding RSUs and reflects a weighted average contractual life of one year |
Disposition
Disposition | 12 Months Ended |
Dec. 31, 2020 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposition | DISPOSITION On April 16, 2019, Fortis sold its 51% ownership interest in the 335 MW Waneta Expansion for proceeds of $995 million. A gain on disposition of $577 million ($484 million after tax), net of expenses, was recognized in the Corporate and Other segment, and the related non-controlling interest was removed from equity. Up to the date of disposition, excluding the gain as noted above, the Waneta Expansion contributed $17 million to earnings before income tax expense, of which Fortis' share was 51%. |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2020 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | OTHER INCOME, NET (in millions) 2020 2019 Equity component of AFUDC $ 78 $ 74 Equity income 20 (1) Derivative gains 13 17 Interest income 13 16 Gain on repayment of debt — 11 Other 30 21 $ 154 $ 138 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES Deferred Income Tax Assets and Liabilities The significant components of deferred income tax assets and liabilities consisted of the following. (in millions) 2020 2019 Gross deferred income tax assets Regulatory liabilities $ 527 $ 588 Tax loss and credit carryforwards 494 532 Employee future benefits 175 165 Unrealized foreign exchange losses on long-term debt (1) 33 40 Other 83 88 1,312 1,413 Valuation allowance (1) (22) (22) Net deferred income tax asset $ 1,290 $ 1,391 Gross deferred income tax liabilities PPE $ (4,253) $ (3,986) Regulatory assets (263) (269) Intangible assets (118) (105) (4,634) (4,360) Net deferred income tax liability $ (3,344) $ (2,969) (1) These deferred income tax assets can be utilized only to the extent that the Corporation has capital gains to offset the underlying capital losses. Management believes that it is more likely than not that a $22 million shortfall exists in this regard and, therefore, the Corporation has recognized a $22 million valuation allowance. Management believes that, based on its historical pattern of taxable income, Fortis will generate the necessary income in the future to realize all other deferred income tax assets. Unrecognized Tax Benefits (in millions) 2020 2019 Beginning of year $ 36 $ 38 Additions related to current year 3 5 Adjustments related to prior years (6) (7) End of year $ 33 $ 36 Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2020. Fortis has not recognized interest expense in 2020 and 2019 related to unrecognized tax benefits. Income Tax Expense (in millions) 2020 2019 Canadian Earnings before income tax expense $ 333 $ 901 Current income tax 20 49 Deferred income tax (16) 42 Total Canadian $ 4 $ 91 Foreign Earnings before income tax expense $ 1,287 $ 1,240 Current income tax (15) (7) Deferred income tax 242 205 Total Foreign $ 227 $ 198 Income tax expense $ 231 $ 289 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 as noted) 2020 2019 Earnings before income tax expense $ 1,620 $ 2,141 Combined Canadian federal and provincial statutory income tax rate (%) 30.0 28.5 Expected federal and provincial taxes at statutory rate $ 486 $ 610 Decrease resulting from: Foreign and other statutory rate differentials (145) (124) Difference between gain on sale for accounting and amounts calculated for tax purposes — (73) Release of valuation allowance — (33) AFUDC (20) (16) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (56) (48) Items capitalized for accounting purposes but expensed for income tax purposes (26) (17) Other (8) (10) Income tax expense $ 231 $ 289 Effective tax rate (%) 14.3 13.5 Income Tax Carryforwards (in millions) Expiring Year 2020 Canadian Capital loss n/a $ 27 Non-capital loss 2035-2040 200 Other tax credits 2026-2040 2 229 Unrecognized (26) 203 Foreign Federal and state net operating loss 2021-2040 2,971 Other tax credits 2022-2040 34 3,005 Total income tax carryforwards recognized $ 3,208 The Corporation and certain 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 income tax compliance examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal and British Columbia). The Corporation's 2013 to 2020 taxation years are still open for audit in Canadian jurisdictions, and its 2011 to 2020 taxation years are still open for audit in United States jurisdictions. |
Employee Future Benefits
Employee Future Benefits | 12 Months Ended |
Dec. 31, 2020 | |
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, 2017 for the Corporation; December 31, 2018 for FortisBC Energy and FortisBC Electric (plan covering unionized employees); December 31, 2019 for the remaining FortisBC Electric plans, Newfoundland Power, FortisAlberta and FortisOntario; and December 31, 2020 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 2020 Target Allocation (weighted average %) 2020 2019 Equities 46 48 47 Fixed income 47 45 46 Real estate 6 6 6 Cash and other 1 1 1 100 100 100 Fair Value of Plan Assets (in millions) Level 1 (1) Level 2 (1) Level 3 (1) Total 2020 Equities $ 713 $ 1,163 $ — $ 1,876 Fixed income 197 1,580 — 1,777 Real estate — 17 204 221 Private equities — — 20 20 Cash and other 8 17 — 25 $ 918 $ 2,777 $ 224 $ 3,919 2019 Equities $ 622 $ 1,050 $ — $ 1,672 Fixed income 171 1,445 — 1,616 Real estate — 16 207 223 Private equities — — 22 22 Cash and other 8 10 — 18 $ 801 $ 2,521 $ 229 $ 3,551 (1) See Note 27 for a description of the fair value hierarchy. The following table reconciles the changes in the fair value of plan assets that have been measured using Level 3 inputs. (in millions) 2020 2019 Balance, beginning of year $ 229 $ 215 (Loss) return on plan assets (2) 19 Foreign currency translation (1) (2) Purchases, sales and settlements (2) (3) Balance, end of year $ 224 $ 229 Funded Status Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Change in benefit obligation (1) Balance, beginning of year $ 3,632 $ 3,207 $ 712 $ 655 Service costs 98 77 32 27 Employee contributions 17 16 2 2 Interest costs 113 124 22 25 Benefits paid (162) (144) (27) (27) Actuarial losses 350 439 62 46 Past service (credits) costs/plan amendments — 1 (3) 4 Foreign currency translation (53) (88) (11) (20) Balance, end of year (2) (3) $ 3,995 $ 3,632 $ 789 $ 712 Change in value of plan assets Balance, beginning of year $ 3,208 $ 2,830 $ 343 $ 293 Actual return on plan assets 444 523 55 62 Benefits paid (155) (138) (27) (27) Employee contributions 17 18 2 2 Employer contributions 62 53 28 28 Foreign currency translation (48) (78) (10) (15) Balance, end of year (4) $ 3,528 $ 3,208 $ 391 $ 343 Funded status $ (467) $ (424) $ (398) $ (369) Balance sheet presentation Long-term assets (Note 9) $ 58 $ 46 $ 8 $ 17 Current liabilities (Note 13) (13) (12) (13) (12) Long-term liabilities (Note 16) (512) (458) (393) (374) $ (467) $ (424) $ (398) $ (369) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation, which excludes assumptions about future salary levels, for defined benefit pension plans was $3,679 million as at December 31, 2020 (2019 - $3,352 million). (3) The increases in the defined benefit pension and OPEB obligations were driven by the decrease in discount rates due to lower interest rates. (4) The increases in the defined benefit pension and OPEB plan assets were driven by market returns. For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the obligation was $3,290 million compared to plan assets of $2,777 million (2019 - $2,971 million and $2,511 million, respectively). For those defined benefit pension plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the obligation was $3,037 million compared to plan assets of $2,741 million (2019 - $2,752 million and $2,478 million, respectively). For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the obligation was $589 million compared to plan assets of $183 million (2019 - $537 million and $151 million, respectively). Net Benefit Cost (1) Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Service costs $ 98 $ 77 $ 32 $ 27 Interest costs 113 124 22 25 Expected return on plan assets (176) (161) (19) (16) Amortization of actuarial losses (gains) 33 24 (5) (4) Amortization of past service credits/plan amendments (1) (1) (2) (7) Regulatory adjustments — 2 4 3 $ 67 $ 65 $ 32 $ 28 (1) The non-service cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings. 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 OPEB Plans (in millions) 2020 2019 2020 2019 Unamortized net actuarial losses (gains) $ 42 $ 32 $ (1) $ (2) Unamortized past service costs 1 1 7 7 Income tax recovery (10) (8) (1) (1) Accumulated other comprehensive income $ 33 $ 25 $ 5 $ 4 Net actuarial losses (gains) $ 517 $ 486 $ 12 $ (18) Past service credits (7) (9) (8) (8) Other regulatory deferrals 13 15 18 19 $ 523 $ 492 $ 22 $ (7) Regulatory assets (Note 8) $ 523 $ 492 $ 65 $ 38 Regulatory liabilities (Note 8) — — (43) (45) Net regulatory assets (liabilities) $ 523 $ 492 $ 22 $ (7) The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets. Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Current year net actuarial losses $ 9 $ 11 $ 1 $ — Past service costs/plan amendments — — — 5 Amortization of actuarial losses 1 1 — — Foreign currency translation — 1 — — Income tax recovery (2) (5) — — Total recognized in comprehensive income $ 8 $ 8 $ 1 $ 5 Current year net actuarial losses $ 69 $ 64 $ 25 $ 3 Past service costs (credits)/plan amendments — — (3) — Amortization of actuarial (losses) gains (31) (23) 5 4 Amortization of past service (costs) credits 2 (1) 3 8 Foreign currency translation (7) (10) — — Regulatory adjustments (2) — (1) (8) Total recognized in regulatory assets $ 31 $ 30 $ 29 $ 7 Significant Assumptions Defined Benefit OPEB Plans (weighted average %) 2020 2019 2020 2019 Discount rate during the year (1) 3.16 4.05 3.22 4.10 Discount rate as at December 31 2.63 3.20 2.64 3.25 Expected long-term rate of return on plan assets (2) 5.52 5.78 5.28 5.50 Rate of compensation increase 3.34 3.33 — — Health care cost trend increase as at December 31 (3) — — 4.61 4.62 (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 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 2021 weighted average health care cost trend rate is 5.91% and is assumed to decrease over the next 11 years to the weighted average ultimate health care cost trend rate of 4.61% in 2031 and thereafter. Expected Benefit Payments Defined Benefit OPEB (in millions) Pension Payments Payments 2021 $ 163 $ 27 2022 165 28 2023 170 30 2024 174 31 2025 180 32 2026-2030 984 174 During 2021 the Corporation expects to contribute $49 million for defined benefit pension plans and $33 million for OPEB plans. In 2020 the Corporation expensed $42 million (2019 - $39 million) related to defined contribution pension plans. |
Supplementary Cash Flow Informa
Supplementary Cash Flow Information | 12 Months Ended |
Dec. 31, 2020 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Cash Flow Information | SUPPLEMENTARY CASH FLOW INFORMATION (in millions) 2020 2019 Cash paid (received) for Interest $ 1,027 $ 1,007 Income taxes (26) (37) Change in working capital Accounts receivable and other current assets $ (84) $ 1 Prepaid expenses (15) (8) Inventories (36) (13) Regulatory assets - current portion (49) (75) Accounts payable and other current liabilities (100) (8) Regulatory liabilities - current portion (150) (65) $ (434) $ (168) Non-cash investing and financing activities Accrued capital expenditures $ 400 $ 382 Common share dividends reinvested 114 299 Contributions in aid of construction 13 15 Right-of-use assets obtained in exchange for operating lease liabilities 3 55 Exercise of stock options into common shares 3 5 Finance leases 2 88 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments and Risk Management | 12 Months Ended |
Dec. 31, 2020 | |
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 flow. Cash flow associated with the settlement of all derivatives is included in operating activities on the consolidated statements of cash flows. Energy Contracts Subject to Regulatory Deferral UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values are 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 are measured using forward pricing provided by independent third-party information. FortisBC Energy holds gas supply contracts 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, 2020, unrealized losses of $73 million (2019 - $119 million) were recognized as regulatory assets and unrealized gains of $17 million (2019 - $2 million) were recognized as regulatory liabilities. Energy Contracts Not Subject to Regulatory Deferral UNS Energy holds wholesale trading contracts to fix power prices and realize potential margin, of which 10% of any realized gains is shared with customers through rate stabilization accounts. Fair values are measured using a market approach incorporating, where possible, independent third-party information. 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 are 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 revenue and were not material for 2020 and 2019. Total Return Swaps The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $113 million and terms of one g at varying dates through January 2023. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net and were not material for 2020 and 2019. Foreign Exchange Contracts The Corporation holds US dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through February 2022 and have a combined notional amount of $245 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net and were not material for 2020 and 2019. Interest Rate Swaps ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with planned borrowings. The swaps, which had a combined notional value of $611 million, were terminated in May 2020 with the issuance of US$700 million senior notes. Realized losses of $31 million were recognized in other comprehensive income and are being reclassified to earnings as a component of interest expense over five years. 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 are recognized in other income, net and were not material for 2020 and 2019. Recurring Fair Value Measures The following table presents derivative 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, 2020 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 38 $ — $ 38 Energy contracts not subject to regulatory deferral (2) — 6 — 6 Foreign exchange contracts and total return swaps (2) 16 — — 16 Other investments (4) 126 — — 126 $ 142 $ 44 $ — $ 186 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ — $ (94) $ — $ (94) Energy contracts not subject to regulatory deferral (5) — (12) — (12) $ — $ (106) $ — $ (106) As at December 31, 2019 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 22 $ — $ 22 Energy contracts not subject to regulatory deferral (2) — 8 — 8 Foreign exchange contracts, interest rate and total return swaps (2) 14 4 — 18 Other investments (4) 121 — — 121 $ 135 $ 34 $ — $ 169 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ (1) $ (138) $ — $ (139) Energy contracts not subject to regulatory deferral (5) — (12) — (12) $ (1) $ (150) $ — $ (151) (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 The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which apply only to its energy contracts. The following table presents the potential offset of counterparty netting. (in millions) Gross Counterparty Cash Net As at December 31, 2020 Derivative assets $ 44 $ 26 $ 10 $ 8 Derivative liabilities (106) (26) (9) (71) As at December 31, 2019 Derivative assets $ 30 $ 22 $ 10 $ (2) Derivative liabilities (151) (22) (2) (127) Volume of Derivative Activity As at December 31, 2020, 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. 2020 2019 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 522 628 Electricity power purchase contracts (GWh) 2,781 3,198 Gas swap contracts (PJ) 156 168 Gas supply contract premiums (PJ) 203 241 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 1,588 1,855 Gas swap contracts (PJ) 36 43 (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. As a result of the impact of the COVID-19 pandemic, certain of the Corporation's utilities have temporarily suspended non-payment disconnects, delayed customer rate increases and deferred the recovery of costs (Note 2). The Corporation has seen an increase in accounts receivable and, accordingly, its allowance for credit losses during 2020 (Note 6). ITC has a concentration of credit risk as approxima tely 70% of its revenue is derived from three customers. The customers have investment-grade credit ratings and credit risk is further managed by MISO by requiring a letter of credit or cash deposit equal to the cre dit 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. Credit risk is managed by obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, 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 managed 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 $88 million as at December 31, 2020 (2019 - $161 million). Hedge of Foreign Net Investments The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Belize Electric Company Limited and Belize Electricity is, or is pegged to, the US dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has limited this exposure through hedging. As at December 31, 2020, US$2.3 billion (2019 - US$2.2 billion) of corporately issued US dollar-denominated long-term debt has been designated as an effective hedge of net investments, leaving approximately US$10.2 billion (2019 - US$9.7 billion) 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 remaining financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES As at December 31, 2020, unconditional minimum purchase obligations were as follows. (in millions) Total Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Waneta Expansion capacity agreement (1) $ 2,576 $ 52 $ 53 $ 54 $ 55 $ 56 $ 2,306 Gas and fuel purchase obligations (2) 2,355 679 453 312 192 124 595 Power purchase obligations (3) 1,867 249 208 188 191 180 851 Renewable PPAs (4) 1,380 102 102 101 101 101 873 ITC easement agreement (5) 381 13 13 13 13 13 316 Debt collection agreement (6) 112 3 3 3 3 3 97 Renewable energy credit purchase agreements (7) 97 15 14 16 9 7 36 Other (8) 116 48 5 4 4 3 52 $ 8,884 $ 1,161 $ 851 $ 691 $ 568 $ 487 $ 5,126 (1) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion for forty-years, beginning April 2015. (2) FortisBC Energy ($1,482 million): includes contracts for the purchase of gas, gas transportation and storage services, expiring in 2062. 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, 2020. UNS Energy ($747 million): includes 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 through 2040. (3) Maritime Electric ($910 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 December 2026. FortisOntario ($599 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 through December 2030. FortisBC Electric ($295 million): 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. (4) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. Amounts are the estimated future payments. (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 unless METC gives notice of non-renewal at least one year in advance. (6) 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. (7) 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 generation. Payments are primarily made at contractually agreed-upon intervals based on metered energy production. (8) Includes a $24 million payment to be made in 2021 under the Oso Grande Wind Project build-transfer agreement by UNS Energy, as well as AROs and joint-use asset and shared service agreements. Other Commitments Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $155 million of equity capital to the Wataynikaneyap Partnership, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the related project. In October 2019 the Wataynikaneyap Partnership entered into loan agreements to finance the project during construction. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of $235 million. UNS Energy has joint generation performance guarantees with participants at San Juan, Four Corners, and Luna, with agreements expiring in 2022 through 2046, and at Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $318 million for Four Corners. As at December 31, 2020, there was no obligation under these guarantees. Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. Central Hudson's maximum commitment is $94 million, for which it has issued a parental guarantee. As at December 31, 2020, there was no obligation under this guarantee. As at December 31, 2020, FortisBC Holdings Inc. ("FHI") had $69 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. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2020 | |
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 a controlled variable interest entity up to the date of its disposition on April 16, 2019 (Note 22). 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 Credit Losses | Allowance for Credit Losses Fortis and its subsidiaries recognize an allowance for credit losses (2019 - allowance for doubtful accounts) to reduce accounts receivable for amounts estimated to be uncollectible. The allowance for credit losses is estimated based on historical collection patterns, sales, and current and forecast economic and other conditions. 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: (i) 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; or (ii) obligations to provide future service that customers have paid for in advance. |
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 8) 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. Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC for 2020 totalled $41 million (2019 - $40 million) and 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 AESO toward funding the construction of transmission facilities. Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulator, UNS Energy and Central Hudson recognize 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 2020 ranged from 0.9% to 39.8% (2019 - 0.9% to 35.0%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.5% for 2020 (2019 – 2.6%). The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows. 2020 2019 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 32 5-80 32 Gas 18-95 38 15-95 36 Transmission Electric 20-90 43 20-90 43 Gas 10-85 35 5-85 32 Generation 1-85 24 1-85 25 Other 2-70 14 3-70 14 |
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 33.0% for 2020 (2019 – 1.0% to 33.0%). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2020 2019 (years) Service Life Weighted Service Life Weighted Computer software 3-15 4 3-10 4 Land, transmission and water rights 43-90 56 43-90 58 Other 10-100 12 10-100 12 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. |
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. Goodwill at each of the Corporation's 11 reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized. The Corporation performs a qualitative assessment on each reporting unit, and if it is determined that it is not likely that fair value is less than carrying value, then a quantitative estimate of fair value is not required. When a quantitative assessment is necessary, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market approach along with a reconciliation of the total estimated fair value of all the reporting units to the Corporation's market capitalization, is also performed and evaluated. |
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 each subsidiary maintain 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 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 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 8). |
Leases | Leases A right-of-use asset and lease liability is recognized for all leases with a lease term greater than 12 months. The right-of-use asset and liability are both measured at the present value of future lease payments, excluding variable payments that are based on usage or performance. Future lease payments include both lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which Fortis accounts for as a single lease component. The present value is calculated using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. Renewal options are included in the lease term when it is reasonably certain that the option will be exercised. Finance 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. |
Revenue Recognition | Revenue Recognition 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. Energy sales are 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. 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 is 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. |
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. DSUs, PSUs and RSUs issued pre-2020 represent cash-settled awards and RSUs issued in 2020 represent cash or share-settled awards, depending on settlement elections and share ownership requirements of the executive. 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, 2020 was $52.36 (2019 - $53.97). 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. |
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 accumulat ed other comprehensive income. The exchange rate as at December 31, 2020 was US$1.00=CA$1.27 ( 2019 – US$1.00=CA$1.30). 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=CA$1.34 for 2020 (2019 - US$1.00=CA$1.33). 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. |
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, PSU 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 recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8). 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 Fortis, ITC and UNS Energy use cash flow hedges, from time to time, 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 certain 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 of, 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 BECOL are not subject to income tax. Differences between the income tax expense or recovery recognized under US GAAP and 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 8). 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 $3.4 billion as at December 31, 2020 (2019 - $2.8 billion). 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, rights-of-way 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 16) 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. Accretion and depreciation expense are deferred as a regulatory asset or liability based on regulatory recovery of these costs. Actual settlement costs are recognized as a reduction in the accrued liability. |
Contingencies | Contingencies Fortis and its subsidiaries are subject to various legal proceedings and claims 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 periods of time. Actual outcomes may differ materially from the amounts recognized. |
New Accounting Policies | New Accounting Policies Financial Instruments Effective January 1, 2020, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-13, Measurement of Credit Losses on Financial Instruments , which requires the use of reasonable and supportable forecasts in the estimation of credit losses and the recognition of expected losses upon initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. Adoption did not have a material impact on the consolidated financial statements and related disclosures. Future Accounting Pronouncements The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board. Any ASUs not included in these consolidated financial statements were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements. |
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. |
Regulation (Tables)
Regulation (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Schedule of Nature of Regulation | Nature of Regulation Allowed Common Equity (%) Allowed ROE (1) (%) Regulatory Authority 2020 2019 Significant Features ITC (2) (3) Federal Energy Regulatory Commission ("FERC") 60.0 10.77 10.63 Cost-based formula rates, with annual true-up mechanism (4) Incentive adders TEP Arizona Corporation Commission ("ACC") (5) FERC (6) 50.0 9.75 9.75 COS regulation Historical test year Formula transmission rates 54.0 10.40 10.40 UNS Electric ACC 52.8 9.50 9.50 UNS Gas ACC 50.8 9.75 9.75 Central Hudson (7) New York State Public Service Commission ("PSC") 50.0 8.80 8.80 COS regulation FortisBC Energy British Columbia Utilities Commission ("BCUC") 38.5 8.75 8.75 COS regulation with formula components and incentives (8) FortisBC Electric BCUC 40.0 9.15 9.15 Future test year FortisAlberta Alberta Utilities Commission ("AUC") 37.0 8.50 8.50 PBR (9) Newfoundland Power Newfoundland and Labrador Board of Commissioners of Public Utilities 45.0 8.50 8.50 COS regulation Maritime Electric Island Regulatory and Appeals Commission 40.0 9.35 9.35 COS regulation FortisOntario (10) Ontario Energy Board 40.0 8.52-9.30 8.78-9.30 COS regulation with incentive mechanisms Caribbean Utilities (11) Utility Regulation and Competition Office N/A 6.75-8.75 7.50-9.50 COS regulation Rate-cap adjustment mechanism based on published consumer price indices FortisTCI (12) Government of the Turks and Caicos Islands N/A 15.00-17.50 15.00-17.50 COS regulation (1) ROA for Caribbean Utilities and FortisTCI (2) Includes the allowed common equity and base ROE plus incentive adders for ITCTransmission, METC, and ITC Midwest (3) Including incentive adders, the May 2020 FERC decision implies an all-in ROE for ITC's subsidiaries operating in the Midcontinent Independent System Operator ("MISO") region of 10.77%, up from 10.63% as set in the November 2019 decision. See "Significant Regulatory Developments" below (4) Annual true-up reflected in rates within a two-year period (5) Effective January 1, 2021, 53% allowed common equity and 9.15% ROE with 0.20% return on the fair value increment. See "COVID-19 Pandemic Impacts - Delayed and Postponed Regulatory Proceedings" below (6) Approved effective August 1, 2019, subject to refund following hearing and settlement procedures. As at December 31, 2020, $19 million (2019 - $5 million) has been reserved as a regulatory liability (7) Pursuant to a three-year settlement agreement arising from a 2017 general rate application, Central Hudson's rates reflect a capital structure of 48%, 49% and 50% common equity as of July 1, 2018, 2019 and 2020, respectively. See "COVID-19 Pandemic Impacts - Delayed and Postponed Regulatory Proceedings" below (8) Formula and incentives have been set through 2024. See "Significant Regulatory Developments" below (9) FortisAlberta is subject to PBR including mechanisms for flow-through costs and capital expenditures not otherwise recovered through customer rates. FortisAlberta's current PBR term expires as of December 31, 2022 (10) Two of FortisOntario's utilities follow COS regulation with incentive mechanisms, while the remaining utility is subject to a 35-year franchise agreement expiring in 2033 (11) Operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial 20-year period, expiring in April 2028, with a provision for automatic renewal. Its non-exclusive generation licence is for a 25-year term, expiring in November 2039 (12) Operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Schedule of Property Plant and Equipment | The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows. 2020 2019 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 32 5-80 32 Gas 18-95 38 15-95 36 Transmission Electric 20-90 43 20-90 43 Gas 10-85 35 5-85 32 Generation 1-85 24 1-85 25 Other 2-70 14 3-70 14 (in millions) Cost Accumulated Depreciation Net Book Value 2020 Distribution Electric $ 11,921 $ (3,223) $ 8,698 Gas 5,546 (1,422) 4,124 Transmission Electric 15,888 (3,413) 12,475 Gas 2,360 (719) 1,641 Generation 6,441 (2,550) 3,891 Other 4,178 (1,347) 2,831 Assets under construction 2,012 — 2,012 Land 326 — 326 $ 48,672 $ (12,674) $ 35,998 2019 Distribution Electric $ 11,396 $ (3,125) $ 8,271 Gas 5,277 (1,330) 3,947 Transmission Electric 15,207 (3,293) 11,914 Gas 2,267 (681) 1,586 Generation 6,380 (2,472) 3,908 Other 4,042 (1,327) 2,715 Assets under construction 1,329 — 1,329 Land 318 — 318 $ 46,216 $ (12,228) $ 33,988 |
Schedule of Intangible Assets | The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2020 2019 (years) Service Life Weighted Service Life Weighted Computer software 3-15 4 3-10 4 Land, transmission and water rights 43-90 56 43-90 58 Other 10-100 12 10-100 12 Accumulated Net Book (in millions ) Cost Amortization Value 2020 Computer software $ 932 $ (524) $ 408 Land, transmission and water rights 898 (142) 756 Other 114 (64) 50 Assets under construction 77 — 77 $ 2,021 $ (730) $ 1,291 2019 Computer software $ 946 $ (576) $ 370 Land, transmission and water rights 890 (122) 768 Other 115 (61) 54 Assets under construction 68 — 68 $ 2,019 $ (759) $ 1,260 |
Segmented Information (Tables)
Segmented Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
Schedule of Inter-Company Transactions Between Non-Regulated and Regulated Entities | Inter-company balances, transactions and profit between non-regulated and regulated entities, which are not eliminated on consolidation, are summarized below. (in millions) 2020 2019 Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy $ 25 $ 23 Sale of capacity from the Waneta Expansion to FortisBC Electric (1) — 17 |
Schedule of Information by Reportable Segment | REGULATED NON-REGULATED Year ended Energy Inter- December 31, 2020 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 $ 1,744 $ 2,260 $ 953 $ 1,385 $ 596 $ 424 $ 1,485 $ 8,847 $ 88 $ — $ — $ 8,935 Energy supply costs — 847 232 468 — 119 893 2,559 3 — — 2,562 Operating expenses 438 627 503 341 148 117 194 2,368 30 39 — 2,437 Depreciation and amortization 295 330 90 237 212 61 183 1,408 16 4 — 1,428 Operating income 1,011 456 128 339 236 127 215 2,512 39 (43) — 2,508 Other income, net 40 40 31 8 2 5 10 136 5 13 — 154 Finance charges 324 125 48 142 104 72 77 892 — 150 — 1,042 Income tax expense 179 69 20 29 1 4 21 323 5 (97) — 231 Net earnings 548 302 91 176 133 56 127 1,433 39 (83) — 1,389 Non-controlling interests 99 — — 1 — — 15 115 — — — 115 Preference share dividends — — — — — — — — — 65 — 65 Net earnings attributable to common equity shareholders $ 449 $ 302 $ 91 $ 175 $ 133 $ 56 $ 112 $ 1,318 $ 39 $ (148) $ — $ 1,209 Goodwill $ 7,810 $ 1,758 $ 574 $ 913 $ 228 $ 235 $ 247 $ 11,765 $ 27 $ — $ — $ 11,792 Total assets 20,358 10,802 3,939 7,695 5,084 2,441 4,261 54,580 745 209 (53) 55,481 Capital expenditures 1,182 1,200 339 471 420 135 273 4,020 19 — — 4,039 Year ended December 31, 2019 (in millions) Revenue $ 1,761 $ 2,212 $ 917 $ 1,331 $ 598 $ 418 $ 1,467 $ 8,704 $ 82 $ — $ (3) $ 8,783 Energy supply costs — 814 254 438 — 121 890 2,517 3 — — 2,520 Operating expenses 489 650 451 333 145 107 188 2,363 36 56 (3) 2,452 Depreciation and amortization 270 297 79 235 214 62 171 1,328 20 2 — 1,350 Gain on disposition — — — — — — — — — 577 — 577 Operating income 1,002 451 133 325 239 128 218 2,496 23 519 — 3,038 Other income, net 37 28 17 16 2 4 2 106 2 30 — 138 Finance charges 290 130 46 136 104 72 77 855 — 180 — 1,035 Income tax expense 174 57 19 39 6 6 20 321 (1) (31) — 289 Net earnings 575 292 85 166 131 54 123 1,426 26 400 — 1,852 Non-controlling interests 104 — — 1 — — 17 122 8 — — 130 Preference share dividends — — — — — — — — — 67 — 67 Net earnings attributable to common equity shareholders $ 471 $ 292 $ 85 $ 165 $ 131 $ 54 $ 106 $ 1,304 $ 18 $ 333 $ — $ 1,655 Goodwill $ 7,970 $ 1,794 $ 586 $ 913 $ 228 $ 235 $ 251 $ 11,977 $ 27 $ — $ — $ 12,004 Total assets 19,799 10,205 3,726 7,305 4,831 2,328 4,185 52,379 711 641 (327) 53,404 Capital expenditures 1,148 915 317 463 423 106 295 3,667 28 25 — 3,720 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Revenue | (in millions) 2020 2019 Electric and gas revenue United States ITC $ 1,726 $ 1,697 UNS Energy 2,019 1,966 Central Hudson 941 894 Canada FortisBC Energy 1,336 1,289 FortisAlberta 580 576 FortisBC Electric 358 362 Newfoundland Power 707 671 Maritime Electric 215 209 FortisOntario 222 206 Caribbean Caribbean Utilities 238 270 FortisTCI 77 85 Total electric and gas revenue 8,419 8,225 Other services revenue (1) 325 374 Revenue from contracts with customers 8,744 8,599 Alternative revenue (2) 64 116 Other revenue 127 68 Total revenue $ 8,935 $ 8,783 (1) Includes $227 million and $273 million from regulated operations for 2020 and 2019, respectively (2) Includes a $40 million and $91 million base ROE adjustment associated with the May 2020 and November 2 019 FERC decisions, respectively (Notes 2 and 8) |
Accounts Receivable and Other_2
Accounts Receivable and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Receivables [Abstract] | |
Schedule Of Accounts Receivable and Other Current Assets | (in millions) 2020 2019 Trade accounts receivable $ 595 $ 504 Unbilled accounts receivable 571 601 Allowance for credit losses (1) (64) (35) 1,102 1,070 Income tax receivable 72 35 Other (2) 195 192 $ 1,369 $ 1,297 (1) Allowance for doubtful accounts for 2019 (2) Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 27) |
Schedule of Allowance for Credit Losses | The allowance for credit losses balance changed during 2020 as follows. (in millions) 2020 Balance, beginning of year $ (35) Credit loss expensed (36) Credit loss deferred (Note 2) (6) Write-offs, net of recoveries 14 Foreign exchange (1) Balance, end of year $ (64) The allowance for doubtful accounts balance changed during 2019 as follows. (in millions) 2019 Balance, beginning of year $ (33) Bad debt expensed (21) Write-offs, net of recoveries 18 Foreign exchange 1 Balance, end of year $ (35) |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Inventory Disclosure [Abstract] | |
Schedule of Utility Inventory | (in millions) 2020 2019 Materials and supplies $ 297 $ 294 Gas and fuel in storage 101 69 Coal inventory 24 31 $ 422 $ 394 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | (in millions ) 2020 2019 Regulatory assets Deferred income taxes (Notes 3 and 24) $ 1,697 $ 1,556 Employee future benefits (Notes 3 and 25) 588 530 Deferred energy management costs (1) 334 279 Rate stabilization and related accounts (2) 213 208 Deferred lease costs (3) 122 116 Manufactured gas plant site remediation deferral (Note 16) 107 81 Derivatives (Notes 3 and 27) 73 119 Generation early retirement costs (4) 55 88 Other regulatory assets (5) 399 406 Total regulatory assets 3,588 3,383 Less: Current portion (470) (425) Long-term regulatory assets $ 3,118 $ 2,958 Regulatory liabilities Deferred income taxes (Notes 3 and 24) $ 1,361 $ 1,440 Asset removal cost provision (Note 3) 1,206 1,187 Rate stabilization and related accounts (2) 104 166 Renewable energy surcharge (6) 100 94 Energy efficiency liability (7) 83 101 Employee future benefits (Notes 3 and 25) 43 45 Electric and gas moderator account (8) 28 45 ROE complaints liability (Note 2) 16 91 Other regulatory liabilities (5) 162 189 Total regulatory liabilities 3,103 3,358 Less: Current portion (441) (572) Long-term regulatory liabilities $ 2,662 $ 2,786 (1) 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 two to 10 years. (2) 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 of 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 5). (3) Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under the 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. (4) Generation Early Retirement Costs: TEP and the co-owners of Navajo Generating Station ("Navajo") retired Navajo in 2019, with related decommissioning activities continuing through 2054. TEP also retired Sundt Generating Facility Units 1 and 2 ("Sundt") in 2019. The ACC approved the recovery of the retirement costs of Navajo and Sundt over a 10-year period as part of the 2020 Rate Order (Note 2). (5) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million. (6) 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 a 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 ("RECs"). 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 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount. (7) 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. (8) 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. |
Schedule of Regulatory Liabilities | (in millions ) 2020 2019 Regulatory assets Deferred income taxes (Notes 3 and 24) $ 1,697 $ 1,556 Employee future benefits (Notes 3 and 25) 588 530 Deferred energy management costs (1) 334 279 Rate stabilization and related accounts (2) 213 208 Deferred lease costs (3) 122 116 Manufactured gas plant site remediation deferral (Note 16) 107 81 Derivatives (Notes 3 and 27) 73 119 Generation early retirement costs (4) 55 88 Other regulatory assets (5) 399 406 Total regulatory assets 3,588 3,383 Less: Current portion (470) (425) Long-term regulatory assets $ 3,118 $ 2,958 Regulatory liabilities Deferred income taxes (Notes 3 and 24) $ 1,361 $ 1,440 Asset removal cost provision (Note 3) 1,206 1,187 Rate stabilization and related accounts (2) 104 166 Renewable energy surcharge (6) 100 94 Energy efficiency liability (7) 83 101 Employee future benefits (Notes 3 and 25) 43 45 Electric and gas moderator account (8) 28 45 ROE complaints liability (Note 2) 16 91 Other regulatory liabilities (5) 162 189 Total regulatory liabilities 3,103 3,358 Less: Current portion (441) (572) Long-term regulatory liabilities $ 2,662 $ 2,786 (1) 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 two to 10 years. (2) 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 of 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 5). (3) Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under the 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. (4) Generation Early Retirement Costs: TEP and the co-owners of Navajo Generating Station ("Navajo") retired Navajo in 2019, with related decommissioning activities continuing through 2054. TEP also retired Sundt Generating Facility Units 1 and 2 ("Sundt") in 2019. The ACC approved the recovery of the retirement costs of Navajo and Sundt over a 10-year period as part of the 2020 Rate Order (Note 2). (5) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million. (6) 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 a 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 ("RECs"). 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 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount. (7) 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. (8) 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. |
Other Assets (Tables)
Other Assets (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of Other Assets | (in millions) 2020 2019 Supplemental Executive Retirement Plan ("SERP") $ 155 $ 145 Renewable Energy Credits (Note 8) 106 99 Equity investment - Belize Electricity 80 71 Employee future benefits (Note 25) 66 63 Other investments 66 43 Operating leases (Note 15) 40 46 Deferred compensation plan 36 30 Equity Investment - Wataynikaneyap Partnership 12 12 Other (1) 109 111 $ 670 $ 620 (1) Includes the fair value of derivatives (Note 27) |
Property, Plant And Equipment (
Property, Plant And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Schedule of Property Plant and Equipment | The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows. 2020 2019 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 32 5-80 32 Gas 18-95 38 15-95 36 Transmission Electric 20-90 43 20-90 43 Gas 10-85 35 5-85 32 Generation 1-85 24 1-85 25 Other 2-70 14 3-70 14 (in millions) Cost Accumulated Depreciation Net Book Value 2020 Distribution Electric $ 11,921 $ (3,223) $ 8,698 Gas 5,546 (1,422) 4,124 Transmission Electric 15,888 (3,413) 12,475 Gas 2,360 (719) 1,641 Generation 6,441 (2,550) 3,891 Other 4,178 (1,347) 2,831 Assets under construction 2,012 — 2,012 Land 326 — 326 $ 48,672 $ (12,674) $ 35,998 2019 Distribution Electric $ 11,396 $ (3,125) $ 8,271 Gas 5,277 (1,330) 3,947 Transmission Electric 15,207 (3,293) 11,914 Gas 2,267 (681) 1,586 Generation 6,380 (2,472) 3,908 Other 4,042 (1,327) 2,715 Assets under construction 1,329 — 1,329 Land 318 — 318 $ 46,216 $ (12,228) $ 33,988 |
Schedule of Jointly-Owned Facilities | As at December 31, 2020, interests in jointly owned facilities consisted of the following. Ownership Accumulated Net Book (in millions, except as noted) (%) Cost Depreciation Value Transmission Facilities 1.0-80.0 $ 980 $ (381) $ 599 Springerville Common Facilities (1) 86.0 505 (251) 254 San Juan Unit 1 ("San Juan") 50.0 370 (304) 66 Springerville Coal Handling Facilities 83.0 268 (121) 147 Four Corners Units 4 and 5 ("Four Corners") 7.0 235 (97) 138 Gila River Common Facilities 50.0 108 (36) 72 Luna Energy Facility ("Luna") 33.3 74 (2) 72 $ 2,540 $ (1,192) $ 1,348 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Indefinite-Lived Intangible Assets | Accumulated Net Book (in millions ) Cost Amortization Value 2020 Computer software $ 932 $ (524) $ 408 Land, transmission and water rights 898 (142) 756 Other 114 (64) 50 Assets under construction 77 — 77 $ 2,021 $ (730) $ 1,291 2019 Computer software $ 946 $ (576) $ 370 Land, transmission and water rights 890 (122) 768 Other 115 (61) 54 Assets under construction 68 — 68 $ 2,019 $ (759) $ 1,260 |
Schedule of Intangible Assets | The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2020 2019 (years) Service Life Weighted Service Life Weighted Computer software 3-15 4 3-10 4 Land, transmission and water rights 43-90 56 43-90 58 Other 10-100 12 10-100 12 Accumulated Net Book (in millions ) Cost Amortization Value 2020 Computer software $ 932 $ (524) $ 408 Land, transmission and water rights 898 (142) 756 Other 114 (64) 50 Assets under construction 77 — 77 $ 2,021 $ (730) $ 1,291 2019 Computer software $ 946 $ (576) $ 370 Land, transmission and water rights 890 (122) 768 Other 115 (61) 54 Assets under construction 68 — 68 $ 2,019 $ (759) $ 1,260 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | (in millions) 2020 2019 Balance, beginning of year $ 12,004 $ 12,530 Foreign currency translation impacts (1) (212) (526) Balance, end of year $ 11,792 $ 12,004 (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, 2020 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other Current Liabilities | (in millions) 2020 2019 Trade accounts payable $ 707 $ 754 Employee compensation and benefits payable 248 229 Dividends payable 241 228 Accrued taxes other than income taxes 224 223 Interest payable 215 212 Customer and other deposits 214 226 Gas and fuel cost payable 188 225 Fair value of derivatives (Note 27) 56 83 Manufactured gas plant site remediation (Note 16) 31 31 Employee future benefits (Note 25) 26 24 Other 171 167 $ 2,321 $ 2,402 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | (in millions ) Maturity Date 2020 2019 ITC Secured US First Mortgage Bonds - 4.31% weighted average fixed rate (2019 - 4.46%) 2024-2055 $ 2,755 $ 2,624 Secured US Senior Notes - 4.00% weighted average fixed rate (2019 - 4.26%) 2040-2055 923 747 Unsecured US Senior Notes - 3.61% weighted average fixed rate (2019 - 3.79%) 2022-2043 4,136 3,312 Unsecured US Shareholder Note - 6.00% fixed rate (2019 - 6.00%) 2028 253 258 Unsecured US Term Loan Credit Agreement - 2.35% weighted average fixed rate n/a — 260 UNS Energy Unsecured US Tax-Exempt Bonds - 4.34% weighted average fixed and variable rate (2019 - 4.64%) 2029-2030 362 603 Unsecured US Fixed Rate Notes - 3.86% weighted average fixed rate (2019 - 4.38%) 2021-2050 2,704 1,851 Central Hudson Unsecured US Promissory Notes - 3.94% weighted average fixed and variable rate (2019 - 4.27%) 2021-2060 1,078 986 FortisBC Energy Unsecured Debentures - 4.72% weighted average fixed rate (2019 - 4.87%) 2026-2050 2,995 2,795 FortisAlberta Unsecured Debentures - 4.49% weighted average fixed rate (2019 - 4.64%) 2024-2052 2,360 2,185 FortisBC Electric Secured Debentures - 8.80% fixed rate (2019 - 8.80%) 2023 25 25 Unsecured Debentures - 4.87% weighted average fixed rate (2019 - 5.05%) 2021-2050 785 710 Other Electric Secured First Mortgage Sinking Fund Bonds - 5.61% weighted average fixed rate (2019 - 6.14%) 2022-2060 634 571 Secured First Mortgage Bonds - 5.66% weighted average fixed rate (2019 - 5.66%) 2025-2061 220 220 Unsecured Senior Notes - 4.45% weighted average fixed rate (2019 - 4.45%) 2041-2048 152 152 Unsecured US Senior Loan Notes and Bonds - 4.41% weighted average fixed and variable rate (2019 - 4.53%) 2022-2049 648 645 Corporate and Other Unsecured US Senior Notes and Promissory Notes - 3.81% weighted average fixed rate (2019 - 3.80%) 2021-2044 2,685 2,903 Unsecured Debentures - 6.50% fixed rate (2019 - 6.50%) 2039 200 200 Unsecured Senior Notes - 2.85% fixed rate (2019 - 2.85%) 2023 500 500 Long-term classification of credit facility borrowings 980 640 Fair value adjustment - ITC acquisition 119 133 Total long-term debt (Note 27) 24,514 22,320 Less: Deferred financing costs and debt discounts (147) (129) Less: Current installments of long-term debt (1,254) (690) $ 23,113 $ 21,501 (in millions, except as noted) Month Issued Interest Rate (%) Maturity Amount ($) Use of Proceeds ITC Unsecured term loan credit agreement January (1) 2021 US 75 (2)(3) Unsecured term loan credit agreement (4) January (5) 2021 US 200 (4) Unsecured senior notes May 2.95 2030 US 700 (2)(3)(6) First mortgage bonds July 3.13 2051 US 180 (2)(3)(7) Secured senior notes October 3.02 2055 US 150 (2)(3)(7)(8) UNS Energy Unsecured senior notes April 4.00 2050 US 350 (2)(3) Unsecured senior notes August 1.50 2030 US 300 (7) Unsecured senior notes September 2.17 2032 US 50 (2)(3) Central Hudson Unsecured senior notes May 3.42 2050 US 30 (3) Unsecured senior notes July 3.62 2060 US 30 (3)(7) Unsecured senior notes September 2.03 2030 US 40 (8) Unsecured senior notes November 2.03 2030 US 30 (3)(7) FortisBC Energy Unsecured debentures July 2.54 2050 200 (7) FortisAlberta Unsecured senior debentures December 2.63 2051 175 (2) FortisBC Electric Unsecured debentures May 3.12 2050 75 (2) Newfoundland Power First mortgage sinking fund bonds April 3.61 2060 100 (2)(3) FortisTCI Unsecured senior notes June/October 5.30 2035 US 30 (7)(8) Unsecured senior notes October/December 3.25 2030 US 10 (3) (1) Floating rate of a one-month LIBOR plus a spread of 0.45% (2) Repay credit facility borrowings (3) General corporate purposes (4) Maximum amount of borrowings under this agreement of US$400 million has been drawn; current period borrowings were used to repay an outstanding commercial paper balance. (5) Floating rate of a two-month LIBOR plus a spread of 0.60% (6) Early redemption of unsecured term loan borrowing of US$400 million (7) Finance capital expenditures (8) Repay maturing long-term debt |
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. (in millions) Total 2021 $ 1,254 2022 823 2023 1,786 2024 1,088 2025 484 Thereafter 19,079 $ 24,514 |
Schedule of Credit Facilities | (in millions) Regulated Corporate 2020 2019 Total credit facilities $ 3,700 $ 1,881 $ 5,581 $ 5,590 Credit facilities utilized: Short-term borrowings (1) (132) — (132) (512) Long-term debt (including current portion) (2) (714) (266) (980) (640) Letters of credit outstanding (77) (53) (130) (114) Credit facilities unutilized $ 2,777 $ 1,562 $ 4,339 $ 4,324 (1) The weighted average interest rate was approximately 0.8% (2019 - 3.2%). (2) The weighted average interest rate was approximately 0.9% (2019 - 2.4% ) . The current portion was $651 million (2019 - $252 million). Consolidated credit facilities of approximately $5.6 billion as at December 31, 2020 are itemized below. (in millions) Amount ($) Maturity Unsecured committed revolving credit facilities Regulated utilities ITC (1) US 900 October 2023 UNS Energy US 500 October 2022 Central Hudson US 200 March 2025 FortisBC Energy 700 August 2024 FortisAlberta 250 August 2024 FortisBC Electric 150 April 2024 Other Electric 190 (2) Other Electric US 70 January 2025 Corporate and Other 1,850 (3) Other facilities Regulated utilities Central Hudson - uncommitted credit facility US 30 n/a FortisBC Energy - uncommitted credit facility 55 March 2022 FortisBC Electric - unsecured demand overdraft facility 10 n/a Other Electric - unsecured demand facilities 20 n/a Other Electric - unsecured demand facility and emergency standby loan US 60 June 2021 Corporate and Other - unsecured non-revolving facility 30 n/a (1) ITC also has a US$400 million commercial paper program, under which US$67 million was outstanding as at December 31, 2020, as reported in short-term borrowings. (2) $40 million in June 2021, $50 million in February 2022 and $100 million in August 2024 (3) $500 million in April 2021, $50 million in April 2022 and $1.3 billion in July 2024 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Schedule of Operating and Finance Leases Balance Sheet Location | Leases were presented on the consolidated balance sheets as follows. (in millions) 2020 2019 Operating leases Other assets $ 40 $ 46 Accounts payable and other current liabilities (7) (8) Other liabilities (33) (38) Finance leases (1) (2) Regulatory assets $ 122 $ 116 PPE, net 211 308 Accounts payable and other current liabilities (2) (24) Finance leases (331) (413) (1) FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates to the use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, which includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the capital cost of the BTS, and related variable operating costs. (2) In December 2020 TEP purchased a 32.2% undivided interest in the Springerville Common Facilities, which had previously been leased (Note 10). |
Components of Lease Expense and Supplemental Lease Information | The components of lease expense were as follows. (in millions) 2020 2019 Operating lease cost $ 10 $ 10 Finance lease cost: Amortization 14 17 Interest 34 48 Variable lease cost 20 39 Total lease cost $ 78 $ 114 Supplemental lease information was as follows. (in millions, except as noted) 2020 2019 Weighted average remaining lease term (years) Operating leases 10 10 Finance leases 35 27 Weighted average discount rate (%) Operating leases 4.0 4.1 Finance leases 5.1 4.8 Cash payments related to lease liabilities Operating cash flows used for operating leases $ (10) $ (10) Operating cash flows used for finance leases (2) (47) Financing cash flows used for finance leases (25) (16) Investing cash flows used for finance leases (87) (212) |
Present Value of Minimum Finance Lease Payments | As at December 31, 2020, the present value of minimum lease payments was as follows. (in millions) Operating Leases Finance Total 2021 $ 8 $ 33 $ 41 2022 7 34 41 2023 6 34 40 2024 4 34 38 2025 3 34 37 Thereafter 22 1,056 1,078 50 1,225 1,275 Less: Imputed interest (10) (892) (902) Total lease obligations 40 333 373 Less: Current installments (7) (2) (9) $ 33 $ 331 $ 364 |
Present Value of Minimum Operating Lease Payments | As at December 31, 2020, the present value of minimum lease payments was as follows. (in millions) Operating Leases Finance Total 2021 $ 8 $ 33 $ 41 2022 7 34 41 2023 6 34 40 2024 4 34 38 2025 3 34 37 Thereafter 22 1,056 1,078 50 1,225 1,275 Less: Imputed interest (10) (892) (902) Total lease obligations 40 333 373 Less: Current installments (7) (2) (9) $ 33 $ 331 $ 364 |
Other Liabilities (Tables)
Other Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Other Liabilities Disclosure [Abstract] | |
Schedule of Other Liabilities | (in millions) 2020 2019 Employee future benefits (Note 25) $ 905 $ 832 Customer and other deposits 132 70 AROs (Note 3) 130 148 Stock-based compensation plans (Note 21) 86 83 Manufactured gas plant site remediation (1) 69 48 Fair value of derivatives (Note 27) 50 68 Mine reclamation obligations (2) 47 43 Retail energy contract (3) 46 — Deferred compensation plan (Note 9) 43 33 Operating leases 33 38 Other 58 83 $ 1,599 $ 1,446 (1) Environmental regulations require Central Hudson to investigate sites at which it 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, 2020, an obligation of $96 million was recognized, including a current portion of $27 million recognized in accounts payable and other current liabilities (Note 13). 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 8). (2) TEP pays ongoing reclamation costs related to two 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 $61 million upon expiry of the coal agreements between 2022 and 2031. The present value of the estimated future liability is shown in the table above. (3) FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment in 2020 which will be amortized to earnings over the life of the agreement. |
Earnings Per Common Share (Tabl
Earnings Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings per Common Share | Diluted earnings per common share ("EPS") was calculated using the treasury stock method for options. 2020 2019 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares EPS Shareholders Shares EPS ($ millions) (# millions) ($) ($ millions) (# millions) ($) Basic EPS $ 1,209 464.8 $ 2.60 $ 1,655 436.8 $ 3.79 Potential dilutive effect of stock options — 0.6 — — 0.7 — Diluted EPS $ 1,209 465.4 $ 2.60 $ 1,655 437.5 $ 3.78 |
Preference Shares (Tables)
Preference Shares (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Equity [Abstract] | |
Schedule of Preference Shares Issued and Outstanding | Issued and Outstanding 2020 2019 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 7,665 188 7,025 172 Series I 2,335 57 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. 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 — Currently Redeemable 25.00 — Series J (3) 4.75 1.1875 — Currently Redeemable 25.25 — Fixed rate reset (4) (5) Series G 5.25 1.0983 2.13 September 1, 2023 25.00 — Series H (6) 4.25 0.4588 1.45 June 1, 2025 25.00 Series I Series K 4.00 0.9823 2.05 March 1, 2024 25.00 Series L Series M 4.10 0.9783 2.48 December 1, 2024 25.00 Series N Floating rate reset (5) (7) Series I 2.10 — 1.45 June 1, 2025 25.00 Series H Series L — — — — — Series K Series N — — — — — 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 are redeemable as of December 1, 2021 and thereafter at $25.00 per share. (4) On the redemption and/or conversion option date, and on 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 H was reset from $0.6250 to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025. (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, 2020 | |
Equity [Abstract] | |
Change in Accumulated Other Comprehensive Income by Category | (in millions) Opening Balance Net Change Ending Balance 2020 Unrealized foreign currency translation gains (losses) Net investments in foreign operations $ 713 $ (336) $ 377 Hedges of net investments in foreign operations (359) 60 (299) Income tax expense (3) (3) (6) 351 (279) 72 Other Cash flow hedges (Note 27) 17 (21) (4) Unrealized employee future benefits losses (Note 25) (38) (11) (49) Income tax recovery 6 9 15 (15) (23) (38) Accumulated other comprehensive income $ 336 $ (302) $ 34 2019 Unrealized foreign currency translation gains (losses) Net investments in foreign operations $ 1,470 $ (757) $ 713 Hedges of net investments in foreign operations (544) 185 (359) Income tax recovery (expense) 10 (13) (3) 936 (585) 351 Other Cash flow hedges (Note 27) 11 6 17 Unrealized employee future benefits losses (Note 25) (20) (18) (38) Income tax recovery 1 5 6 (8) (7) (15) Accumulated other comprehensive income $ 928 $ (592) $ 336 |
Stock-based Compensation Plans
Stock-based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
Schedule of Stock Option Information | The following options were granted in 2020 and 2019. 2020 2019 Options granted (in thousands) 686 852 Exercise price ($) (1) 58.40 47.57 Grant date fair value ($) 4.20 3.70 Valuation assumptions: Dividend yield (%) (2) 3.7 3.8 Expected volatility (%) (3) 15.8 15.2 Risk-free interest rate (%) (4) 1.2 1.8 Weighted average expected life (years) (5) 5.2 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 2020. Total Options Non-vested Options (1) (in thousands, except as noted) Number of Options Weighted Average Number of Options Weighted Average Options outstanding, beginning of year 3,418 $ 41.18 1,910 $ 3.43 Granted 686 $ 58.40 686 $ 4.20 Exercised (825) $ 39.21 n/a n/a Vested n/a n/a (807) $ 3.25 Cancelled/Forfeited (17) $ 50.02 (17) $ 3.79 Options outstanding, end of year 3,262 $ 45.26 1,772 $ 3.81 Options vested, end of year (2) 1,490 $ 39.40 (1) As at December 31, 2020, there was $7 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, 2020, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $19 million. |
Schedule of Additional Stock Option Information | The following table summarizes additional stock option information. (in millions) 2020 2019 Stock options exercised: Cash received for exercise price $ 32 $ 51 Intrinsic value realized by employees 15 22 |
DSU Plan Activity | The following table summarizes information related to DSUs. 2020 2019 Number of units (in thousands) Beginning of year 165 177 Granted 25 29 Notional dividends reinvested 6 6 Paid out (49) (47) End of year 147 165 |
PSU Plans Activity | The following table summarizes information related to PSUs. 2020 2019 Number of units (in thousands) Beginning of year 2,118 1,763 Granted 586 690 Notional dividends reinvested 71 73 Paid out (735) (357) Cancelled/forfeited (64) (51) End of year 1,976 2,118 Additional information (in millions) Compensation expense recognized $ 58 $ 74 Compensation expense unrecognized (1) 32 35 Cash payout 54 16 Accrued liability as at December 31 (2) 108 106 Aggregate intrinsic value as at December 31 (3) 140 141 (1) Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years (2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16) (3) 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. 2020 2019 Number of units (in thousands) Beginning of year 1,050 717 Granted 356 429 Notional dividends reinvested 37 35 Paid out (355) (92) Cancelled/forfeited (40) (39) End of year 1,048 1,050 Additional information (in millions) Compensation expense recognized $ 20 $ 24 Compensation expense unrecognized (1) 15 17 Cash payout 19 4 Accrued liability as at December 31 (2) 39 39 Aggregate intrinsic value as at December 31 (3) 54 56 (1) Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years (2) Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16) (3) 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, 2020 | |
Other Income and Expenses [Abstract] | |
Schedule of Other Income, Net | (in millions) 2020 2019 Equity component of AFUDC $ 78 $ 74 Equity income 20 (1) Derivative gains 13 17 Interest income 13 16 Gain on repayment of debt — 11 Other 30 21 $ 154 $ 138 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Schedule of Deferred Income Tax Assets and Liabilities | The significant components of deferred income tax assets and liabilities consisted of the following. (in millions) 2020 2019 Gross deferred income tax assets Regulatory liabilities $ 527 $ 588 Tax loss and credit carryforwards 494 532 Employee future benefits 175 165 Unrealized foreign exchange losses on long-term debt (1) 33 40 Other 83 88 1,312 1,413 Valuation allowance (1) (22) (22) Net deferred income tax asset $ 1,290 $ 1,391 Gross deferred income tax liabilities PPE $ (4,253) $ (3,986) Regulatory assets (263) (269) Intangible assets (118) (105) (4,634) (4,360) Net deferred income tax liability $ (3,344) $ (2,969) (1) These deferred income tax assets can be utilized only to the extent that the Corporation has capital gains to offset the underlying capital losses. Management believes that it is more likely than not that a $22 million shortfall exists in this regard and, therefore, the Corporation has recognized a $22 million valuation allowance. Management believes that, based on its historical pattern of taxable income, Fortis will generate the necessary income in the future to realize all other deferred income tax assets. |
Schedule of Unrecognized Tax Benefits | Unrecognized Tax Benefits (in millions) 2020 2019 Beginning of year $ 36 $ 38 Additions related to current year 3 5 Adjustments related to prior years (6) (7) End of year $ 33 $ 36 |
Schedule of Components of Income Tax Expense | Income Tax Expense (in millions) 2020 2019 Canadian Earnings before income tax expense $ 333 $ 901 Current income tax 20 49 Deferred income tax (16) 42 Total Canadian $ 4 $ 91 Foreign Earnings before income tax expense $ 1,287 $ 1,240 Current income tax (15) (7) Deferred income tax 242 205 Total Foreign $ 227 $ 198 Income tax expense $ 231 $ 289 |
Schedule of Effective Income Tax Rate Reconciliation | The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes. (in millions, except as noted) 2020 2019 Earnings before income tax expense $ 1,620 $ 2,141 Combined Canadian federal and provincial statutory income tax rate (%) 30.0 28.5 Expected federal and provincial taxes at statutory rate $ 486 $ 610 Decrease resulting from: Foreign and other statutory rate differentials (145) (124) Difference between gain on sale for accounting and amounts calculated for tax purposes — (73) Release of valuation allowance — (33) AFUDC (20) (16) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (56) (48) Items capitalized for accounting purposes but expensed for income tax purposes (26) (17) Other (8) (10) Income tax expense $ 231 $ 289 Effective tax rate (%) 14.3 13.5 |
Summary of Operating Loss Carryforwards | Income Tax Carryforwards (in millions) Expiring Year 2020 Canadian Capital loss n/a $ 27 Non-capital loss 2035-2040 200 Other tax credits 2026-2040 2 229 Unrecognized (26) 203 Foreign Federal and state net operating loss 2021-2040 2,971 Other tax credits 2022-2040 34 3,005 Total income tax carryforwards recognized $ 3,208 |
Summary of Tax Carryforward Amounts | Income Tax Carryforwards (in millions) Expiring Year 2020 Canadian Capital loss n/a $ 27 Non-capital loss 2035-2040 200 Other tax credits 2026-2040 2 229 Unrecognized (26) 203 Foreign Federal and state net operating loss 2021-2040 2,971 Other tax credits 2022-2040 34 3,005 Total income tax carryforwards recognized $ 3,208 |
Employee Future Benefits (Table
Employee Future Benefits (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Retirement Benefits [Abstract] | |
Schedule of Allocation of Plan Assets | Allocation of Plan Assets 2020 Target Allocation (weighted average %) 2020 2019 Equities 46 48 47 Fixed income 47 45 46 Real estate 6 6 6 Cash and other 1 1 1 100 100 100 Fair Value of Plan Assets (in millions) Level 1 (1) Level 2 (1) Level 3 (1) Total 2020 Equities $ 713 $ 1,163 $ — $ 1,876 Fixed income 197 1,580 — 1,777 Real estate — 17 204 221 Private equities — — 20 20 Cash and other 8 17 — 25 $ 918 $ 2,777 $ 224 $ 3,919 2019 Equities $ 622 $ 1,050 $ — $ 1,672 Fixed income 171 1,445 — 1,616 Real estate — 16 207 223 Private equities — — 22 22 Cash and other 8 10 — 18 $ 801 $ 2,521 $ 229 $ 3,551 (1) See Note 27 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 plan assets that have been measured using Level 3 inputs. (in millions) 2020 2019 Balance, beginning of year $ 229 $ 215 (Loss) return on plan assets (2) 19 Foreign currency translation (1) (2) Purchases, sales and settlements (2) (3) Balance, end of year $ 224 $ 229 |
Schedule of Amounts Recognized in Balance Sheet | Funded Status Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Change in benefit obligation (1) Balance, beginning of year $ 3,632 $ 3,207 $ 712 $ 655 Service costs 98 77 32 27 Employee contributions 17 16 2 2 Interest costs 113 124 22 25 Benefits paid (162) (144) (27) (27) Actuarial losses 350 439 62 46 Past service (credits) costs/plan amendments — 1 (3) 4 Foreign currency translation (53) (88) (11) (20) Balance, end of year (2) (3) $ 3,995 $ 3,632 $ 789 $ 712 Change in value of plan assets Balance, beginning of year $ 3,208 $ 2,830 $ 343 $ 293 Actual return on plan assets 444 523 55 62 Benefits paid (155) (138) (27) (27) Employee contributions 17 18 2 2 Employer contributions 62 53 28 28 Foreign currency translation (48) (78) (10) (15) Balance, end of year (4) $ 3,528 $ 3,208 $ 391 $ 343 Funded status $ (467) $ (424) $ (398) $ (369) Balance sheet presentation Long-term assets (Note 9) $ 58 $ 46 $ 8 $ 17 Current liabilities (Note 13) (13) (12) (13) (12) Long-term liabilities (Note 16) (512) (458) (393) (374) $ (467) $ (424) $ (398) $ (369) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation, which excludes assumptions about future salary levels, for defined benefit pension plans was $3,679 million as at December 31, 2020 (2019 - $3,352 million). (3) The increases in the defined benefit pension and OPEB obligations were driven by the decrease in discount rates due to lower interest rates. (4) The increases in the defined benefit pension and OPEB plan assets were driven by market returns. |
Schedule of Funded Status | Funded Status Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Change in benefit obligation (1) Balance, beginning of year $ 3,632 $ 3,207 $ 712 $ 655 Service costs 98 77 32 27 Employee contributions 17 16 2 2 Interest costs 113 124 22 25 Benefits paid (162) (144) (27) (27) Actuarial losses 350 439 62 46 Past service (credits) costs/plan amendments — 1 (3) 4 Foreign currency translation (53) (88) (11) (20) Balance, end of year (2) (3) $ 3,995 $ 3,632 $ 789 $ 712 Change in value of plan assets Balance, beginning of year $ 3,208 $ 2,830 $ 343 $ 293 Actual return on plan assets 444 523 55 62 Benefits paid (155) (138) (27) (27) Employee contributions 17 18 2 2 Employer contributions 62 53 28 28 Foreign currency translation (48) (78) (10) (15) Balance, end of year (4) $ 3,528 $ 3,208 $ 391 $ 343 Funded status $ (467) $ (424) $ (398) $ (369) Balance sheet presentation Long-term assets (Note 9) $ 58 $ 46 $ 8 $ 17 Current liabilities (Note 13) (13) (12) (13) (12) Long-term liabilities (Note 16) (512) (458) (393) (374) $ (467) $ (424) $ (398) $ (369) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation, which excludes assumptions about future salary levels, for defined benefit pension plans was $3,679 million as at December 31, 2020 (2019 - $3,352 million). (3) The increases in the defined benefit pension and OPEB obligations were driven by the decrease in discount rates due to lower interest rates. (4) The increases in the defined benefit pension and OPEB plan assets were driven by market returns. |
Schedule of Net Benefit Costs | Net Benefit Cost (1) Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Service costs $ 98 $ 77 $ 32 $ 27 Interest costs 113 124 22 25 Expected return on plan assets (176) (161) (19) (16) Amortization of actuarial losses (gains) 33 24 (5) (4) Amortization of past service credits/plan amendments (1) (1) (2) (7) Regulatory adjustments — 2 4 3 $ 67 $ 65 $ 32 $ 28 (1) The non-service cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings. |
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 OPEB Plans (in millions) 2020 2019 2020 2019 Unamortized net actuarial losses (gains) $ 42 $ 32 $ (1) $ (2) Unamortized past service costs 1 1 7 7 Income tax recovery (10) (8) (1) (1) Accumulated other comprehensive income $ 33 $ 25 $ 5 $ 4 Net actuarial losses (gains) $ 517 $ 486 $ 12 $ (18) Past service credits (7) (9) (8) (8) Other regulatory deferrals 13 15 18 19 $ 523 $ 492 $ 22 $ (7) Regulatory assets (Note 8) $ 523 $ 492 $ 65 $ 38 Regulatory liabilities (Note 8) — — (43) (45) Net regulatory assets (liabilities) $ 523 $ 492 $ 22 $ (7) |
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. Defined Benefit OPEB Plans (in millions) 2020 2019 2020 2019 Current year net actuarial losses $ 9 $ 11 $ 1 $ — Past service costs/plan amendments — — — 5 Amortization of actuarial losses 1 1 — — Foreign currency translation — 1 — — Income tax recovery (2) (5) — — Total recognized in comprehensive income $ 8 $ 8 $ 1 $ 5 Current year net actuarial losses $ 69 $ 64 $ 25 $ 3 Past service costs (credits)/plan amendments — — (3) — Amortization of actuarial (losses) gains (31) (23) 5 4 Amortization of past service (costs) credits 2 (1) 3 8 Foreign currency translation (7) (10) — — Regulatory adjustments (2) — (1) (8) Total recognized in regulatory assets $ 31 $ 30 $ 29 $ 7 |
Schedule of Assumptions Used | Significant Assumptions Defined Benefit OPEB Plans (weighted average %) 2020 2019 2020 2019 Discount rate during the year (1) 3.16 4.05 3.22 4.10 Discount rate as at December 31 2.63 3.20 2.64 3.25 Expected long-term rate of return on plan assets (2) 5.52 5.78 5.28 5.50 Rate of compensation increase 3.34 3.33 — — Health care cost trend increase as at December 31 (3) — — 4.61 4.62 (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 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. |
Schedule of Expected Benefit Payments | Expected Benefit Payments Defined Benefit OPEB (in millions) Pension Payments Payments 2021 $ 163 $ 27 2022 165 28 2023 170 30 2024 174 31 2025 180 32 2026-2030 984 174 |
Supplementary Cash Flow Infor_2
Supplementary Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | (in millions) 2020 2019 Cash paid (received) for Interest $ 1,027 $ 1,007 Income taxes (26) (37) Change in working capital Accounts receivable and other current assets $ (84) $ 1 Prepaid expenses (15) (8) Inventories (36) (13) Regulatory assets - current portion (49) (75) Accounts payable and other current liabilities (100) (8) Regulatory liabilities - current portion (150) (65) $ (434) $ (168) Non-cash investing and financing activities Accrued capital expenditures $ 400 $ 382 Common share dividends reinvested 114 299 Contributions in aid of construction 13 15 Right-of-use assets obtained in exchange for operating lease liabilities 3 55 Exercise of stock options into common shares 3 5 Finance leases 2 88 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments and Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Fair Value Hierarchy | The following table presents derivative 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, 2020 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 38 $ — $ 38 Energy contracts not subject to regulatory deferral (2) — 6 — 6 Foreign exchange contracts and total return swaps (2) 16 — — 16 Other investments (4) 126 — — 126 $ 142 $ 44 $ — $ 186 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ — $ (94) $ — $ (94) Energy contracts not subject to regulatory deferral (5) — (12) — (12) $ — $ (106) $ — $ (106) As at December 31, 2019 Assets Energy contracts subject to regulatory deferral (2) (3) $ — $ 22 $ — $ 22 Energy contracts not subject to regulatory deferral (2) — 8 — 8 Foreign exchange contracts, interest rate and total return swaps (2) 14 4 — 18 Other investments (4) 121 — — 121 $ 135 $ 34 $ — $ 169 Liabilities Energy contracts subject to regulatory deferral (3) (5) $ (1) $ (138) $ — $ (139) Energy contracts not subject to regulatory deferral (5) — (12) — (12) $ (1) $ (150) $ — $ (151) (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 |
Derivative Asset Contracts Under Master Netting Agreements and Collateral Positions | The following table presents the potential offset of counterparty netting. (in millions) Gross Counterparty Cash Net As at December 31, 2020 Derivative assets $ 44 $ 26 $ 10 $ 8 Derivative liabilities (106) (26) (9) (71) As at December 31, 2019 Derivative assets $ 30 $ 22 $ 10 $ (2) Derivative liabilities (151) (22) (2) (127) |
Derivative Liability Contracts Under Master Netting Agreements and Collateral Positions | The following table presents the potential offset of counterparty netting. (in millions) Gross Counterparty Cash Net As at December 31, 2020 Derivative assets $ 44 $ 26 $ 10 $ 8 Derivative liabilities (106) (26) (9) (71) As at December 31, 2019 Derivative assets $ 30 $ 22 $ 10 $ (2) Derivative liabilities (151) (22) (2) (127) |
Schedule of Volume of Derivative Activity | As at December 31, 2020, 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. 2020 2019 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 522 628 Electricity power purchase contracts (GWh) 2,781 3,198 Gas swap contracts (PJ) 156 168 Gas supply contract premiums (PJ) 203 241 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 1,588 1,855 Gas swap contracts (PJ) 36 43 (1) GWh means gigawatt hours and PJ means petajoules |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Consolidated Commitments in the Next Five Years and Periods Thereafter | As at December 31, 2020, unconditional minimum purchase obligations were as follows. (in millions) Total Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Waneta Expansion capacity agreement (1) $ 2,576 $ 52 $ 53 $ 54 $ 55 $ 56 $ 2,306 Gas and fuel purchase obligations (2) 2,355 679 453 312 192 124 595 Power purchase obligations (3) 1,867 249 208 188 191 180 851 Renewable PPAs (4) 1,380 102 102 101 101 101 873 ITC easement agreement (5) 381 13 13 13 13 13 316 Debt collection agreement (6) 112 3 3 3 3 3 97 Renewable energy credit purchase agreements (7) 97 15 14 16 9 7 36 Other (8) 116 48 5 4 4 3 52 $ 8,884 $ 1,161 $ 851 $ 691 $ 568 $ 487 $ 5,126 (1) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion for forty-years, beginning April 2015. (2) FortisBC Energy ($1,482 million): includes contracts for the purchase of gas, gas transportation and storage services, expiring in 2062. 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, 2020. UNS Energy ($747 million): includes 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 through 2040. (3) Maritime Electric ($910 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 December 2026. FortisOntario ($599 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 through December 2030. FortisBC Electric ($295 million): 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. (4) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. Amounts are the estimated future payments. (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 unless METC gives notice of non-renewal at least one year in advance. (6) 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. (7) 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 generation. Payments are primarily made at contractually agreed-upon intervals based on metered energy production. (8) Includes a $24 million payment to be made in 2021 under the Oso Grande Wind Project build-transfer agreement by UNS Energy, as well as AROs and joint-use asset and shared service agreements. |
Description of Business - Regul
Description of Business - Regulated Utilities (Details) | Dec. 31, 2020stationcompanycommunityMW |
TEP and UNS Electric | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 3,233 |
TEP and UNS Electric | Solar | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 54 |
Central Hudson | Gas-Fired and Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 65 |
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 | 5 |
Newfoundland Power | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 143 |
Newfoundland Power | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 97 |
Maritime Electric | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 130 |
FortisOntario | Electric Utilities | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 5 |
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) | 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% |
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, 2020stationMWBcf | |
BECOL | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating facilities | station | 3 |
Generating capacity (MW) | MW | 51 |
Long-term contract for electric power, term | 50 years |
Aitken Creek | |
Public Utilities, General Disclosures [Line Items] | |
Controlling ownership interest (percent) | 93.80% |
Generating capacity (cubic feet) | Bcf | 77,000,000,000 |
Regulation - Nature of Regulati
Regulation - Nature of Regulation Schedule (Details) $ in Millions | Jan. 01, 2021 | Jul. 01, 2020 | Jul. 01, 2019 | Jul. 01, 2018 | Dec. 31, 2020CAD ($)company | Dec. 31, 2019CAD ($) | Dec. 31, 2017 |
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory liability | $ | $ 3,103 | $ 3,358 | |||||
ITC | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved cost-based formula, annual true-up (period) | 2 years | ||||||
FortisOntario | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Franchise agreement term | 35 years | ||||||
FortisOntario | Electric Utilities, Following COS Regulation | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Number of utilities | company | 2 | ||||||
Fortis Turks and Caicos | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Number of utilities | company | 2 | ||||||
FERC | ITC | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 60.00% | ||||||
Allowed ROE (percent) | 10.77% | 10.63% | |||||
Approved cost-based formula, annual true-up (period) | 2 years | ||||||
FERC | TEP | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 54.00% | ||||||
Allowed ROE (percent) | 10.40% | 10.40% | |||||
Regulatory liability | $ | $ 19 | $ 5 | |||||
ACC | TEP | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 50.00% | ||||||
Allowed ROE (percent) | 9.75% | 9.75% | |||||
ACC | TEP | Forecast | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 53.00% | ||||||
Allowed ROE (percent) | 9.15% | ||||||
Return on fair value increment (percent) | 0.20% | ||||||
ACC | UNS Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 52.80% | ||||||
Allowed ROE (percent) | 9.50% | 9.50% | |||||
ACC | UNS Gas | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 50.80% | ||||||
Allowed ROE (percent) | 9.75% | 9.75% | |||||
PSC | Central Hudson | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 50.00% | 49.00% | 48.00% | 50.00% | |||
Allowed ROE (percent) | 8.80% | 8.80% | |||||
Approved return on equity and capital structure, term | 3 years | ||||||
BCUC | FortisBC Energy | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 38.50% | ||||||
Allowed ROE (percent) | 8.75% | 8.75% | |||||
BCUC | FortisBC Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 40.00% | ||||||
Allowed ROE (percent) | 9.15% | 9.15% | |||||
AUC | FortisAlberta | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 37.00% | ||||||
Allowed ROE (percent) | 8.50% | 8.50% | |||||
PUB | Newfoundland Power | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 45.00% | ||||||
Allowed ROE (percent) | 8.50% | 8.50% | |||||
IRAC | Maritime Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 40.00% | ||||||
Allowed ROE (percent) | 9.35% | 9.35% | |||||
OEB | FortisOntario | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed common equity (percent) | 40.00% | ||||||
OEB | FortisOntario | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed ROE (percent) | 8.52% | 8.78% | |||||
OEB | FortisOntario | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed ROE (percent) | 9.30% | 9.30% | |||||
Government of the Cayman Islands | Caribbean Utilities | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Transmission and distribution license period | 20 years | ||||||
Non-exclusive generation license period | 25 years | ||||||
Government of the Cayman Islands | Caribbean Utilities | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed ROA (percent) | 6.75% | 7.50% | |||||
Government of the Cayman Islands | Caribbean Utilities | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed ROA (percent) | 8.75% | 9.50% | |||||
Government of the Turks and Caicos Islands | Fortis Turks and Caicos | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
License period | 50 years | ||||||
Government of the Turks and Caicos Islands | Fortis Turks and Caicos | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed ROA (percent) | 15.00% | 15.00% | |||||
Government of the Turks and Caicos Islands | Fortis Turks and Caicos | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed ROA (percent) | 17.50% | 17.50% |
Regulation - Customer Relief In
Regulation - Customer Relief Initiatives Narrative (Details) - Utilities Customer Relief Initiatives - CAD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2020 | Apr. 30, 2020 | Dec. 31, 2020 | Mar. 31, 2020 | |
ACC | TEP | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Refund to customers | $ 11 | |||
ACC | UNS Energy | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Payment plan period | 8 months | |||
BCUC | FortisBC Energy and FortisBC Electric | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Period of bill deferrals | 3 months | |||
PSC | Central Hudson | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Deferred collection in customer rates | $ 4 |
Regulation - Delayed and Postpo
Regulation - Delayed and Postponed Regulatory Proceedings Narrative (Details) $ in Millions, $ in Millions | Jan. 01, 2021CAD ($)engineUnits | Jan. 01, 2021USD ($)engineUnits | Oct. 01, 2020 | Jul. 01, 2020 | Jul. 01, 2019 | Jul. 01, 2018 | Dec. 31, 2020CAD ($) | Oct. 31, 2020 | Aug. 31, 2020 | Feb. 29, 2020 | Dec. 31, 2020CAD ($) | Dec. 31, 2019CAD ($) |
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory assets | $ 3,588 | $ 3,588 | $ 3,383 | |||||||||
ACC | TEP | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
ROE (percent) | 9.75% | 9.75% | ||||||||||
Capital structure of common equity (percent) | 50.00% | |||||||||||
ACC | TEP | Forecast | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
ROE (percent) | 9.15% | 9.15% | ||||||||||
Return on fair value increment (percent) | 0.20% | 0.20% | ||||||||||
Capital structure of common equity (percent) | 53.00% | 53.00% | ||||||||||
PSC | Central Hudson | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
ROE (percent) | 8.80% | 8.80% | ||||||||||
Capital structure of common equity (percent) | 50.00% | 49.00% | 48.00% | 50.00% | ||||||||
AUC | FortisAlberta | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
ROE (percent) | 8.50% | 8.50% | ||||||||||
Capital structure of common equity (percent) | 37.00% | |||||||||||
Government Of The Turks And Caicos Islands | FortisTCI | Deferred Incremental Operating Expenses | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory assets | $ 1.5 | $ 1.5 | ||||||||||
Regulatory asset, amortization period | 15 years | |||||||||||
2020 Rate Order | ACC | TEP | Forecast | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Approved rate increase | $ 77 | $ 58 | ||||||||||
ROE (percent) | 9.15% | 9.15% | ||||||||||
Return on fair value increment (percent) | 0.20% | 0.20% | ||||||||||
Capital structure of common equity (percent) | 53.00% | 53.00% | ||||||||||
Rate base | $ 3,500 | $ 2,700 | ||||||||||
Number of natural gas engine units | engineUnits | 10 | 10 | ||||||||||
June 2020 Rates Proceeding | PSC | Central Hudson | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Capital structure of common equity (percent) | 50.00% | 49.00% | ||||||||||
Deferred revenue collection period | 9 months | |||||||||||
General Cost Of Capital Proceeding | AUC | FortisAlberta | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
ROE (percent) | 8.50% | |||||||||||
Capital structure of common equity (percent) | 37.00% | |||||||||||
June 2020 Annual Rate Adjustment | Government of the Cayman Islands | Caribbean Utilities | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Deferred revenue collection period | 2 years | |||||||||||
February 2020 Rate Increase | Government Of The Turks And Caicos Islands | FortisTCI | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Average increase on electricity rates (percent) | 6.80% |
Regulation - Significant Regula
Regulation - Significant Regulatory Developments Narrative (Details) - CAD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||||||
Aug. 31, 2020 | Jun. 30, 2020 | May 31, 2020 | Mar. 31, 2020 | Nov. 30, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2017 | |
Public Utilities, General Disclosures [Line Items] | ||||||||
Regulatory liability | $ 3,103 | $ 3,358 | ||||||
Net earnings | $ 1,209 | $ 1,655 | ||||||
FortisBC Energy and FortisBC Electric | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Variance sharing (percent) | 50.00% | |||||||
FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 10.77% | 10.63% | ||||||
PSC | Central Hudson | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 8.80% | 8.80% | ||||||
BCUC | FortisBC Energy and FortisBC Electric | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Rate-setting framework period | 5 years | |||||||
Variance sharing (percent) | 50.00% | |||||||
AUC | FortisAlberta | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 8.50% | 8.50% | ||||||
May 2020 FERC decision | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE, including incentive adders (percent) | 10.77% | |||||||
Net earnings | $ 29 | |||||||
November 2019 FERC decision | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE, including incentive adders (percent) | 10.63% | |||||||
Net earnings | $ 63 | |||||||
November 2019 And May 2020 FERC decisions | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Refund to customers | 42 | |||||||
November 2019 And May 2020 FERC decisions | FERC | ITC | Return On Equity Complaints Liability | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Regulatory liability | 6 | 91 | ||||||
May 2020 FERC decision, Prior Year Impact | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Net earnings | $ 27 | |||||||
November 2019 FERC decision, Prior Year Impact | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Net earnings | $ 83 | |||||||
March 2020 Review Of Transmission Incentives Policy | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Proposed ROE incentives (basis points) | 2.50% | |||||||
August 2020 Generate Rate Application | PSC | Central Hudson | Electric Delivery Revenue | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Requested increase in rates | $ 44 | |||||||
August 2020 Generate Rate Application | PSC | Central Hudson | Natural Gas Delivery Revenue | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Requested increase in rates | $ 19 | |||||||
2018 Alberta Independent System Operator Tariff Application | AUC | FortisAlberta | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Unamortized customer contributions | $ 400 | |||||||
Minimum | May 2020 FERC decision | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 10.02% | |||||||
Minimum | November 2019 FERC decision | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 9.88% | |||||||
Maximum | May 2020 FERC decision | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 12.62% | |||||||
Maximum | November 2019 FERC decision | FERC | ITC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 12.24% |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Regulated Operations [Abstract] | ||
Debt component of AFUDC | $ 41 | $ 40 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, weighted average composite depreciation rate | 2.50% | 2.60% |
Property, plant and equipment, generation remaining service life | 24 years | 25 years |
Property, plant and equipment, other weighted average remaining service life | 14 years | 14 years |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution weighted average remaining service life | 32 years | 32 years |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution weighted average remaining service life | 38 years | 36 years |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission weighted average remaining service life | 43 years | 43 years |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission weighted average remaining service life | 35 years | 32 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 service life | 1 year | 1 year |
Property, plant and equipment, other service life | 2 years | 3 years |
Minimum | Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution service life | 5 years | 5 years |
Minimum | Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution service life | 18 years | 15 years |
Minimum | Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission service life | 20 years | 20 years |
Minimum | Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission service life | 10 years | 5 years |
Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 39.80% | 35.00% |
Property, plant and equipment, generation service life | 85 years | 85 years |
Property, plant and equipment, other service life | 70 years | 70 years |
Maximum | Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution service life | 80 years | 80 years |
Maximum | Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution service life | 95 years | 95 years |
Maximum | Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission service life | 90 years | 90 years |
Maximum | Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission service life | 85 years | 85 years |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Intangible Assets (Details) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
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 | 56 years | 58 years |
Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 12 years | 12 years |
Minimum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets, straight line depreciation 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 | 43 years | 43 years |
Minimum | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 10 years | 10 years |
Maximum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets, straight line depreciation rate | 33.00% | 33.00% |
Maximum | Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 15 years | 10 years |
Maximum | Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 90 years | 90 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, 2020numberOfReportingUnits | |
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, 2020 | Dec. 31, 2019 | |
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 | |
Volume weighted average share price (period) | 5 days | |
DSUs | Director | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Volume weighted average share price (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | $ 52.36 | $ 53.97 |
PSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Volume weighted average share price (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | $ 52.36 | 53.97 |
RSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Volume weighted average share price (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | $ 52.36 | $ 53.97 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Foreign Currency Translation (Details) - $ / $ | Dec. 31, 2020 | Dec. 31, 2019 |
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items] | ||
Foreign exchange rate (CAD per USD) | 1.27 | 1.30 |
Average | ||
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items] | ||
Foreign exchange rate (CAD per USD) | 1.34 | 1.33 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Income Taxes (Details) - CAD ($) $ in Billions | Dec. 31, 2020 | Dec. 31, 2019 |
Accounting Policies [Abstract] | ||
Undistributed earnings on foreign subsidiaries | $ 3.4 | $ 2.8 |
Segmented Information - Related
Segmented Information - Related-party and Inter-Company Transactions (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Related Party Transaction [Line Items] | ||
Inter-segment loans | $ 0 | $ 279 |
Belize Electricity | Equity Method Investee | ||
Related Party Transaction [Line Items] | ||
Due from related party | 28 | 8 |
Aitken Creek | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | 25 | 23 |
Waneta Expansion | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | $ 0 | $ 17 |
Segmented Information - Informa
Segmented Information - Information by Reportable Segment (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Segment Reporting Information [Line Items] | |||
Revenue | $ 8,935 | $ 8,783 | |
Energy supply costs | 2,562 | 2,520 | |
Operating expenses | 2,437 | 2,452 | |
Depreciation and amortization | 1,428 | 1,350 | |
Gain on disposition | 0 | 577 | |
Operating income | 2,508 | 3,038 | |
Other income, net | 154 | 138 | |
Finance charges | 1,042 | 1,035 | |
Income tax expense | 231 | 289 | |
Net earnings | 1,389 | 1,852 | |
Non-controlling interests | 115 | 130 | |
Preference share dividends | 65 | 67 | |
Common equity shareholders | 1,209 | 1,655 | |
Goodwill | 11,792 | 12,004 | $ 12,530 |
Total assets | 55,481 | 53,404 | |
Capital expenditures | 4,039 | 3,720 | |
Intersegment eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenue | 0 | (3) | |
Energy supply costs | 0 | 0 | |
Operating expenses | 0 | (3) | |
Depreciation and amortization | 0 | 0 | |
Gain on disposition | 0 | ||
Operating income | 0 | 0 | |
Other income, net | 0 | 0 | |
Finance charges | 0 | 0 | |
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 | (53) | (327) | |
Capital expenditures | 0 | 0 | |
REGULATED | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Revenue | 8,847 | 8,704 | |
Energy supply costs | 2,559 | 2,517 | |
Operating expenses | 2,368 | 2,363 | |
Depreciation and amortization | 1,408 | 1,328 | |
Gain on disposition | 0 | ||
Operating income | 2,512 | 2,496 | |
Other income, net | 136 | 106 | |
Finance charges | 892 | 855 | |
Income tax expense | 323 | 321 | |
Net earnings | 1,433 | 1,426 | |
Non-controlling interests | 115 | 122 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 1,318 | 1,304 | |
Goodwill | 11,765 | 11,977 | |
Total assets | 54,580 | 52,379 | |
Capital expenditures | 4,020 | 3,667 | |
REGULATED | Operating Segments | ITC | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,744 | 1,761 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 438 | 489 | |
Depreciation and amortization | 295 | 270 | |
Gain on disposition | 0 | ||
Operating income | 1,011 | 1,002 | |
Other income, net | 40 | 37 | |
Finance charges | 324 | 290 | |
Income tax expense | 179 | 174 | |
Net earnings | 548 | 575 | |
Non-controlling interests | 99 | 104 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 449 | 471 | |
Goodwill | 7,810 | 7,970 | |
Total assets | 20,358 | 19,799 | |
Capital expenditures | 1,182 | 1,148 | |
REGULATED | Operating Segments | UNS Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 2,260 | 2,212 | |
Energy supply costs | 847 | 814 | |
Operating expenses | 627 | 650 | |
Depreciation and amortization | 330 | 297 | |
Gain on disposition | 0 | ||
Operating income | 456 | 451 | |
Other income, net | 40 | 28 | |
Finance charges | 125 | 130 | |
Income tax expense | 69 | 57 | |
Net earnings | 302 | 292 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 302 | 292 | |
Goodwill | 1,758 | 1,794 | |
Total assets | 10,802 | 10,205 | |
Capital expenditures | 1,200 | 915 | |
REGULATED | Operating Segments | Central Hudson | |||
Segment Reporting Information [Line Items] | |||
Revenue | 953 | 917 | |
Energy supply costs | 232 | 254 | |
Operating expenses | 503 | 451 | |
Depreciation and amortization | 90 | 79 | |
Gain on disposition | 0 | ||
Operating income | 128 | 133 | |
Other income, net | 31 | 17 | |
Finance charges | 48 | 46 | |
Income tax expense | 20 | 19 | |
Net earnings | 91 | 85 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 91 | 85 | |
Goodwill | 574 | 586 | |
Total assets | 3,939 | 3,726 | |
Capital expenditures | 339 | 317 | |
REGULATED | Operating Segments | FortisBC Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,385 | 1,331 | |
Energy supply costs | 468 | 438 | |
Operating expenses | 341 | 333 | |
Depreciation and amortization | 237 | 235 | |
Gain on disposition | 0 | ||
Operating income | 339 | 325 | |
Other income, net | 8 | 16 | |
Finance charges | 142 | 136 | |
Income tax expense | 29 | 39 | |
Net earnings | 176 | 166 | |
Non-controlling interests | 1 | 1 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 175 | 165 | |
Goodwill | 913 | 913 | |
Total assets | 7,695 | 7,305 | |
Capital expenditures | 471 | 463 | |
REGULATED | Operating Segments | FortisAlberta | |||
Segment Reporting Information [Line Items] | |||
Revenue | 596 | 598 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 148 | 145 | |
Depreciation and amortization | 212 | 214 | |
Gain on disposition | 0 | ||
Operating income | 236 | 239 | |
Other income, net | 2 | 2 | |
Finance charges | 104 | 104 | |
Income tax expense | 1 | 6 | |
Net earnings | 133 | 131 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 133 | 131 | |
Goodwill | 228 | 228 | |
Total assets | 5,084 | 4,831 | |
Capital expenditures | 420 | 423 | |
REGULATED | Operating Segments | FortisBC Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 424 | 418 | |
Energy supply costs | 119 | 121 | |
Operating expenses | 117 | 107 | |
Depreciation and amortization | 61 | 62 | |
Gain on disposition | 0 | ||
Operating income | 127 | 128 | |
Other income, net | 5 | 4 | |
Finance charges | 72 | 72 | |
Income tax expense | 4 | 6 | |
Net earnings | 56 | 54 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 56 | 54 | |
Goodwill | 235 | 235 | |
Total assets | 2,441 | 2,328 | |
Capital expenditures | 135 | 106 | |
REGULATED | Operating Segments | Other Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,485 | 1,467 | |
Energy supply costs | 893 | 890 | |
Operating expenses | 194 | 188 | |
Depreciation and amortization | 183 | 171 | |
Gain on disposition | 0 | ||
Operating income | 215 | 218 | |
Other income, net | 10 | 2 | |
Finance charges | 77 | 77 | |
Income tax expense | 21 | 20 | |
Net earnings | 127 | 123 | |
Non-controlling interests | 15 | 17 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 112 | 106 | |
Goodwill | 247 | 251 | |
Total assets | 4,261 | 4,185 | |
Capital expenditures | 273 | 295 | |
NON-REGULATED | Operating Segments | Energy Infrastructure | |||
Segment Reporting Information [Line Items] | |||
Revenue | 88 | 82 | |
Energy supply costs | 3 | 3 | |
Operating expenses | 30 | 36 | |
Depreciation and amortization | 16 | 20 | |
Gain on disposition | 0 | ||
Operating income | 39 | 23 | |
Other income, net | 5 | 2 | |
Finance charges | 0 | 0 | |
Income tax expense | 5 | (1) | |
Net earnings | 39 | 26 | |
Non-controlling interests | 0 | 8 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 39 | 18 | |
Goodwill | 27 | 27 | |
Total assets | 745 | 711 | |
Capital expenditures | 19 | 28 | |
NON-REGULATED | Operating Segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Revenue | 0 | 0 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 39 | 56 | |
Depreciation and amortization | 4 | 2 | |
Gain on disposition | 577 | ||
Operating income | (43) | 519 | |
Other income, net | 13 | 30 | |
Finance charges | 150 | 180 | |
Income tax expense | (97) | (31) | |
Net earnings | (83) | 400 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 65 | 67 | |
Common equity shareholders | (148) | 333 | |
Goodwill | 0 | 0 | |
Total assets | 209 | 641 | |
Capital expenditures | $ 0 | $ 25 |
Revenue - Schedule of Revenue (
Revenue - Schedule of Revenue (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 8,744 | $ 8,599 |
Alternative revenue | 64 | 116 |
Other revenue | 127 | 68 |
Revenues | 8,935 | 8,783 |
May 2020 FERC decision | ||
Disaggregation of Revenue [Line Items] | ||
Alternative revenue | 40 | |
November 2019 FERC decision | ||
Disaggregation of Revenue [Line Items] | ||
Alternative revenue | 91 | |
Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 8,419 | 8,225 |
Other services revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 325 | 374 |
Other services revenue | Regulated Operation | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 227 | 273 |
ITC | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,726 | 1,697 |
UNS Energy | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 2,019 | 1,966 |
Central Hudson | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 941 | 894 |
FortisBC Energy | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,336 | 1,289 |
FortisAlberta | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 580 | 576 |
FortisBC Electric | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 358 | 362 |
Newfoundland Power | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 707 | 671 |
Maritime Electric | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 215 | 209 |
FortisOntario | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 222 | 206 |
Caribbean Utilities | Caribbean | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 238 | 270 |
FortisTCI | Caribbean | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 77 | $ 85 |
Revenue - Narrative (Details)
Revenue - Narrative (Details) | 12 Months Ended |
Dec. 31, 2020 | |
ITC | |
Disaggregation of Revenue [Line Items] | |
True-up period | 2 years |
UNS Energy | |
Disaggregation of Revenue [Line Items] | |
Year over year recovery cap | 2.00% |
FortisBC Energy and FortisBC Electric | |
Disaggregation of Revenue [Line Items] | |
Variance sharing (percent) | 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, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Receivables [Abstract] | |||
Trade accounts receivable | $ 595 | $ 504 | |
Unbilled accounts receivable | 571 | 601 | |
Allowance for credit losses | (64) | (35) | $ (33) |
Total accounts receivable | 1,102 | 1,070 | |
Income tax receivable | 72 | 35 | |
Other | 195 | 192 | |
Accounts receivable and other current assets | $ 1,369 | $ 1,297 |
Accounts Receivable and Other_4
Accounts Receivable and Other Current Assets - Schedule of Allowance for Credit Losses (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance, beginning of year | $ (35) | $ (33) |
Credit loss expensed | (36) | (21) |
Credit loss deferred | (6) | |
Write-offs, net of recoveries | 14 | 18 |
Foreign exchange | (1) | 1 |
Balance, end of year | $ (64) | $ (35) |
Inventories (Details)
Inventories (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 422 | $ 394 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 297 | 294 |
Gas and fuel in storage | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 101 | 69 |
Coal inventory | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 24 | $ 31 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 3,588 | $ 3,383 |
Less: Current portion | (470) | (425) |
Long-term regulatory assets | 3,118 | 2,958 |
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 3,103 | 3,358 |
Less: Current portion | (441) | (572) |
Long-term regulatory liabilities | 2,662 | 2,786 |
Deferred income taxes (Notes 3 and 24) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,361 | 1,440 |
Asset removal cost provision (Note 3) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,206 | 1,187 |
Rate stabilization and related accounts | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 104 | 166 |
Renewable energy surcharge | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 100 | 94 |
Renewable energy surcharge | UNS Energy | ||
Regulatory Liabilities [Line Items] | ||
Renewable energy target (at least) (percent) | 15.00% | |
Energy efficiency liability | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 83 | 101 |
Employee future benefits (Notes 3 and 25) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 43 | 45 |
Electric and gas moderator account | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 28 | 45 |
Electric and gas moderator account | Central Hudson | ||
Regulatory Liabilities [Line Items] | ||
Approved rate (period) | 3 years | |
ROE complaints liability (Note 2) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 16 | 91 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 162 | 189 |
Other Regulatory Liabilities, Individually Less Than Threshold | ||
Regulatory Liabilities [Line Items] | ||
Threshold amount, other regulatory liabilities | 40 | |
Deferred income taxes (Notes 3 and 24) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,697 | 1,556 |
Employee future benefits (Notes 3 and 25) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 588 | 530 |
Deferred energy management costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 334 | 279 |
Deferred energy management costs | Minimum | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period | 2 years | |
Deferred energy management costs | Maximum | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period | 10 years | |
Rate stabilization and related accounts | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 213 | 208 |
Deferred lease costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 122 | 116 |
Manufactured gas plant site remediation deferral (Note 16) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 107 | 81 |
Derivatives (Notes 3 and 27) | Energy contracts subject to regulatory deferral | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 73 | 119 |
Generation early retirement costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 55 | 88 |
Remaining recovery period | 10 years | |
Other | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 399 | $ 406 |
Other Regulatory Assets, Individually Less Than Threshold | ||
Regulatory Assets [Line Items] | ||
Threshold amount, other regulatory assets | $ 40 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities - Narrative (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Regulated Operations [Abstract] | ||
Regulatory assets not earning a return | $ 1,678 | $ 1,510 |
Other Assets - Schedule of Othe
Other Assets - Schedule of Other Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Supplemental Executive Retirement Plan ("SERP") | $ 155 | $ 145 |
Renewable Energy Credits (Note 8) | 106 | 99 |
Employee future benefits (Note 25) | 66 | 63 |
Other investments | 66 | 43 |
Deferred compensation plan | 36 | 30 |
Operating leases (Note 15) | 40 | 46 |
Other | 109 | 111 |
Other assets | 670 | 620 |
BEL | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Equity investment | 80 | 71 |
Wataynikaneyap Partnership | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Equity investment | $ 12 | $ 12 |
Property, Plant And Equipment -
Property, Plant And Equipment - Schedule of Utility Capital Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | $ 48,672 | $ 46,216 |
Accumulated Depreciation | (12,674) | (12,228) |
Net Book Value | 35,998 | 33,988 |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 11,921 | 11,396 |
Accumulated Depreciation | (3,223) | (3,125) |
Net Book Value | 8,698 | 8,271 |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 5,546 | 5,277 |
Accumulated Depreciation | (1,422) | (1,330) |
Net Book Value | 4,124 | 3,947 |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 15,888 | 15,207 |
Accumulated Depreciation | (3,413) | (3,293) |
Net Book Value | 12,475 | 11,914 |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 2,360 | 2,267 |
Accumulated Depreciation | (719) | (681) |
Net Book Value | 1,641 | 1,586 |
Generation | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 6,441 | 6,380 |
Accumulated Depreciation | (2,550) | (2,472) |
Net Book Value | 3,891 | 3,908 |
Other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 4,178 | 4,042 |
Accumulated Depreciation | (1,347) | (1,327) |
Net Book Value | 2,831 | 2,715 |
Assets under construction | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 2,012 | 1,329 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | 2,012 | 1,329 |
Land | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 326 | 318 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | $ 326 | $ 318 |
Property, Plant And Equipment_2
Property, Plant And Equipment - Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2020CAD ($)kVkPa | Dec. 31, 2019CAD ($) | |
Regulated Operations [Abstract] | ||
Electric distribution capacity, below (kV) | kV | 69 | |
Gas distribution capacity, below (kPa) | kPa | 2,070 | |
Gas distribution capacity, hoop stress, less than (percent) | 20.00% | |
Electric transmission capacity (kV) | kV | 69 | |
Gas transmission capacity (kPa) | kPa | 2,070 | |
Gas transmission capacity, hoop stress, or more (percent) | 20.00% | |
Cost of PPE under finance leases | $ | $ 322 | $ 514 |
Cost of PPE under finance leases, accumulated depreciation | $ | $ 111 | $ 206 |
Property, Plant And Equipment_3
Property, Plant And Equipment - Schedule of Jointly-Owned Utility Plants (Details) $ in Millions | Dec. 31, 2020CAD ($) |
Jointly Owned Facilities [Line Items] | |
Cost | $ 2,540 |
Accumulated Depreciation | (1,192) |
Net Book Value | $ 1,348 |
Springerville Common Facilities | TEP | |
Jointly Owned Facilities [Line Items] | |
Purchase of undivided interest (percent) | 32.20% |
Sale of ownership interest (percent) | 14.00% |
Transmission Facilities | |
Jointly Owned Facilities [Line Items] | |
Cost | $ 980 |
Accumulated Depreciation | (381) |
Net Book Value | $ 599 |
Transmission Facilities | Minimum | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 1.00% |
Transmission Facilities | Maximum | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 80.00% |
Springerville Common Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 86.00% |
Cost | $ 505 |
Accumulated Depreciation | (251) |
Net Book Value | $ 254 |
San Juan Unit 1 ("San Juan") | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 50.00% |
Cost | $ 370 |
Accumulated Depreciation | (304) |
Net Book Value | $ 66 |
Springerville Coal Handling Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 83.00% |
Cost | $ 268 |
Accumulated Depreciation | (121) |
Net Book Value | $ 147 |
Four Corners Units 4 and 5 ("Four Corners") | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 7.00% |
Cost | $ 235 |
Accumulated Depreciation | (97) |
Net Book Value | $ 138 |
Gila River Common Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 50.00% |
Cost | $ 108 |
Accumulated Depreciation | (36) |
Net Book Value | $ 72 |
Luna Energy Facility ("Luna") | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 33.30% |
Cost | $ 74 |
Accumulated Depreciation | (2) |
Net Book Value | $ 72 |
Intangible Assets - Schedule of
Intangible Assets - Schedule of Intangible Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | $ 2,021 | $ 2,019 |
Accumulated Amortization | (730) | (759) |
Net Book Value | 1,291 | 1,260 |
Land, transmission and water rights | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 898 | 890 |
Accumulated Amortization | (142) | (122) |
Net Book Value | 756 | 768 |
Assets under construction | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 77 | 68 |
Accumulated Amortization | 0 | 0 |
Net Book Value | 77 | 68 |
Computer software | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 932 | 946 |
Accumulated Amortization | (524) | (576) |
Net Book Value | 408 | 370 |
Other | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 114 | 115 |
Accumulated Amortization | (64) | (61) |
Net Book Value | $ 50 | $ 54 |
Intangible Assets - Narrative (
Intangible Assets - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Amortization - intangible assets | $ 131 | $ 125 |
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 | $ 136 | $ 133 |
Goodwill (Details)
Goodwill (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Goodwill [Roll Forward] | ||
Balance, beginning of year | $ 12,004,000,000 | $ 12,530,000,000 |
Foreign currency translation impacts | (212,000,000) | (526,000,000) |
Balance, end of year | 11,792,000,000 | 12,004,000,000 |
Goodwill impairment loss | $ 0 | $ 0 |
Accounts Payable and Other Cu_3
Accounts Payable and Other Current Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Payables and Accruals [Abstract] | ||
Trade accounts payable | $ 707 | $ 754 |
Employee compensation and benefits payable | 248 | 229 |
Dividends payable | 241 | 228 |
Accrued taxes other than income taxes | 224 | 223 |
Interest payable | 215 | 212 |
Customer and other deposits | 214 | 226 |
Gas and fuel cost payable | 188 | 225 |
Fair value of derivatives (Note 27) | 56 | 83 |
Manufactured gas plant site remediation (Note 16) | 31 | 31 |
Employee future benefits (Note 25) | 26 | 24 |
Other | 171 | 167 |
Accounts payable and other current liabilities | $ 2,321 | $ 2,402 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Debt Instrument [Line Items] | ||
Total long-term debt | $ 24,514 | $ 22,320 |
Less: Deferred financing costs and debt discounts | (147) | (129) |
Less: Current installments of long-term debt | (1,254) | (690) |
Long-term debt | 23,113 | 21,501 |
Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | 980 | 640 |
Credit facility | ||
Debt Instrument [Line Items] | ||
Less: Current installments of long-term debt | $ (651) | $ (252) |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 0.90% | 2.40% |
Credit facility | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 980 | $ 640 |
ITC | ||
Debt Instrument [Line Items] | ||
Fair value adjustment - ITC acquisition | 119 | 133 |
ITC | Secured | Fixed Rate Secured US First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,755 | $ 2,624 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.31% | 4.46% |
ITC | Secured | Fixed Rate Secured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 923 | $ 747 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.00% | 4.26% |
ITC | Unsecured | Fixed Rate Unsecured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 4,136 | $ 3,312 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 3.61% | 3.79% |
ITC | Unsecured | Fixed Rate Unsecured US Shareholder Note | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 253 | $ 258 |
Stated interest rate (percent) | 6.00% | 6.00% |
ITC | Unsecured | Fixed Rate Unsecured US Term Loan Credit Agreement | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 0 | $ 260 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 2.35% | |
UNS Energy | Unsecured | Fixed and Variable Rate Unsecured US Tax-Exempt Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 362 | $ 603 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.34% | 4.64% |
UNS Energy | Unsecured | Fixed Rate Unsecured US Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,704 | $ 1,851 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 3.86% | 4.38% |
Central Hudson | Unsecured | Fixed and Variable Rate Unsecured US Promissory Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 1,078 | $ 986 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 3.94% | 4.27% |
FortisBC Energy | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,995 | $ 2,795 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.72% | 4.87% |
FortisAlberta | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,360 | $ 2,185 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.49% | 4.64% |
FortisBC Electric | Secured | Fixed Rate Secured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 25 | $ 25 |
Stated interest rate (percent) | 8.80% | 8.80% |
FortisBC Electric | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 785 | $ 710 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.87% | 5.05% |
Other Electric | Secured | Fixed Rate Secured First Mortgage Sinking Fund Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 634 | $ 571 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 5.61% | 6.14% |
Other Electric | Secured | Fixed Rate Secured First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 220 | $ 220 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 5.66% | 5.66% |
Other Electric | Unsecured | Fixed Rate Unsecured Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 152 | $ 152 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.45% | 4.45% |
Other Electric | Unsecured | Fixed and Variable Rate Unsecured US Senior Loan Notes and Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 648 | $ 645 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 4.41% | 4.53% |
Corporate and Other | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 200 | $ 200 |
Stated interest rate (percent) | 6.50% | 6.50% |
Corporate and Other | Unsecured | Fixed Rate Unsecured US Senior Notes and Promissory Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,685 | $ 2,903 |
Long-term Debt, Weighted Average Interest Rate, at Point in Time | 3.81% | 3.80% |
Corporate and Other | Unsecured | Fixed Rate (Stated) Unsecured Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 500 | $ 500 |
Stated interest rate (percent) | 2.85% | 2.85% |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Dec. 31, 2020CAD ($) | Dec. 31, 2020CAD ($) | Dec. 31, 2019CAD ($) | |
Debt Instrument [Line Items] | |||
Short-form base shelf prospectus, life | 25 months | ||
Short-form base shelf prospectus, principal amount, up to | $ 2,000 | $ 2,000 | |
Short-form base shelf prospectus, remaining amount available | 2,000 | 2,000 | |
Maximum borrowing capacity | 5,581 | 5,581 | $ 5,590 |
Consolidated credit facilities | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | 5,600 | $ 5,600 | |
No one bank | Bank concentration risk | Credit facility | |||
Debt Instrument [Line Items] | |||
Concentration risk percentage | 25.00% | ||
Committed facilities with maturities ranging from 2021 through 2025 | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 5,300 | $ 5,300 | |
Maximum | |||
Debt Instrument [Line Items] | |||
Debt to capital restriction on dividends (percent) | 0.65 | 0.65 |
Long-Term Debt - Long-Term Debt
Long-Term Debt - Long-Term Debt Issuances (Details) $ in Millions, $ in Millions | 1 Months Ended | ||||||||||||
May 31, 2020USD ($) | Jan. 31, 2020USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2020CAD ($) | Nov. 30, 2020USD ($) | Oct. 31, 2020USD ($) | Sep. 30, 2020USD ($) | Aug. 31, 2020USD ($) | Jul. 31, 2020USD ($) | Jul. 31, 2020CAD ($) | May 31, 2020CAD ($) | Apr. 30, 2020USD ($) | Apr. 30, 2020CAD ($) | |
ITC | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Face value | $ 700 | ||||||||||||
ITC | Floating Rate One-Month LIBOR Unsecured Term Loan Credit Agreement | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Face value | $ 75 | ||||||||||||
ITC | Floating Rate One-Month LIBOR Unsecured Term Loan Credit Agreement | Unsecured | LIBOR | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Variable rate (percent) | 0.45% | ||||||||||||
ITC | Floating Rate Two-Month LIBOR Unsecured Term Loan Credit Agreement | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Face value | $ 200 | ||||||||||||
Maximum borrowings | $ 400 | ||||||||||||
ITC | Floating Rate Two-Month LIBOR Unsecured Term Loan Credit Agreement | Unsecured | LIBOR | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Variable rate (percent) | 0.60% | ||||||||||||
ITC | Two Point Nine Five Percent Unsecured Senior Notes | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 2.95% | 2.95% | |||||||||||
Face value | $ 700 | ||||||||||||
Repayments of long-term debt | $ 400 | ||||||||||||
ITC | Three Point One Three Percent First Mortgage Bonds | Secured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.13% | 3.13% | |||||||||||
Face value | $ 180 | ||||||||||||
ITC | Three Point Zero Two Percent Senior Secured Notes | Secured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.02% | ||||||||||||
Face value | $ 150 | ||||||||||||
UNS Energy | Four Percent Senior Unsecured Notes | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 4.00% | 4.00% | |||||||||||
Face value | $ 350 | ||||||||||||
UNS Energy | One Point Five Percent Senior Unsecured Notes | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 1.50% | ||||||||||||
Face value | $ 300 | ||||||||||||
UNS Energy | Two Point One Seven Percent Senior Unsecured Notes | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 2.17% | ||||||||||||
Face value | $ 50 | ||||||||||||
Central Hudson | Three Point Four Two Percent Senior Unsecured Notes | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.42% | 3.42% | |||||||||||
Face value | $ 30 | ||||||||||||
Central Hudson | Three Point Six Two Percent Senior Unsecured Notes | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.62% | 3.62% | |||||||||||
Face value | $ 30 | ||||||||||||
Central Hudson | Two Point Zero Three Percent Senior Unsecured Notes September 2020 | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 2.03% | ||||||||||||
Face value | $ 40 | ||||||||||||
Central Hudson | Two Point Zero Three Percent Senior Unsecured Notes November 2020 | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 2.03% | ||||||||||||
Face value | $ 30 | ||||||||||||
FortisBC Energy | Two Point Five Four Percent Unsecured Debentures | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 2.54% | 2.54% | |||||||||||
Face value | $ 200 | ||||||||||||
FortisBC Electric | Three Point One Two Percent Unsecured Debentures | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.12% | 3.12% | |||||||||||
Face value | $ 75 | ||||||||||||
Newfoundland Power | Three Point Six One Percent First Mortgage Sinking Fund Bonds | Secured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.61% | 3.61% | |||||||||||
Face value | $ 100 | ||||||||||||
FortisTCI | Five point Three Zero Percent Senior Unsecured Notes, June/October 2020 | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 5.30% | ||||||||||||
Face value | $ 30 | ||||||||||||
FortisTCI | Three Point Two Five Percent Senior Unsecured Notes October/December 2020 | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 3.25% | 3.25% | |||||||||||
Face value | $ 10 | ||||||||||||
FortisAlberta | Two Point Six Three Percent Unsecured Senior Debentures | Unsecured | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (percent) | 2.63% | 2.63% | |||||||||||
Face value | $ 175 |
Long-Term Debt - Long-Term De_2
Long-Term Debt - Long-Term Debt Repayments (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Maturities of Long-term Debt [Abstract] | ||
2021 | $ 1,254 | |
2022 | 823 | |
2023 | 1,786 | |
2024 | 1,088 | |
2025 | 484 | |
Thereafter | 19,079 | |
Long-term Debt | $ 24,514 | $ 22,320 |
Long-Term Debt - Schedule of Cr
Long-Term Debt - Schedule of Credit Facilities (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Line of Credit Facility [Line Items] | ||
Total credit facilities | $ 5,581 | $ 5,590 |
Credit facilities utilized: | ||
Short-term borrowings | (132) | (512) |
Long-term debt (including current portion) | (24,514) | (22,320) |
Letters of credit outstanding | (130) | (114) |
Credit facilities unutilized | 4,339 | 4,324 |
Current installments of long-term debt | $ 1,254 | $ 690 |
Credit facility | ||
Credit facilities utilized: | ||
Long-term debt weighted average interest rate (percent) | 0.90% | 2.40% |
Current installments of long-term debt | $ 651 | $ 252 |
Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (980) | (640) |
Long-term Credit Facility Borrowings | Credit facility | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (980) | (640) |
Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | $ (132) | $ (512) |
Short-term debt weighted average interest rate (percent) | 0.80% | 3.20% |
Regulated Operation | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | $ 3,700 | |
Credit facilities utilized: | ||
Letters of credit outstanding | (77) | |
Credit facilities unutilized | 2,777 | |
Regulated Operation | Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (714) | |
Regulated Operation | Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | (132) | |
Corporate and Other | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | 1,881 | |
Credit facilities utilized: | ||
Letters of credit outstanding | (53) | |
Credit facilities unutilized | 1,562 | |
Corporate and Other | Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (266) | |
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, $ in Millions | Dec. 31, 2020CAD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019CAD ($) |
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 5,581 | $ 5,590 | |
Regulated Operation | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 3,700 | ||
Regulated Operation | ITC | Commercial paper | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 400 | ||
Amount outstanding | 67 | ||
Regulated Operation | ITC | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 900 | ||
Regulated Operation | UNS Energy | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 500 | ||
Regulated Operation | Central Hudson | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 200 | ||
Regulated Operation | Central Hudson | Uncommitted credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 30 | ||
Regulated Operation | FortisBC Energy | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 700 | ||
Regulated Operation | FortisBC Energy | Uncommitted credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 55 | ||
Regulated Operation | FortisAlberta | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 250 | ||
Regulated Operation | FortisBC Electric | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 150 | ||
Regulated Operation | FortisBC Electric | Unsecured demand overdraft facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 10 | ||
Regulated Operation | Other Electric | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 190 | 70 | |
Regulated Operation | Other Electric | Unsecured committed revolving credit facility | First redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 40 | ||
Regulated Operation | Other Electric | Unsecured committed revolving credit facility | Second redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 50 | ||
Regulated Operation | Other Electric | Unsecured committed revolving credit facility | Third redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 100 | ||
Regulated Operation | Other Electric | Unsecured demand facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 20 | ||
Regulated Operation | Other Electric | Unsecured demand facility and emergency standby loan | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 60 | ||
NON-REGULATED | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,881 | ||
NON-REGULATED | Corporate And Other - Credit Facilities | Unsecured committed revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,850 | ||
NON-REGULATED | Corporate And Other - Credit Facilities | Unsecured committed revolving credit facility | First redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 500 | ||
NON-REGULATED | Corporate And Other - Credit Facilities | Unsecured committed revolving credit facility | Second redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 50 | ||
NON-REGULATED | Corporate And Other - Credit Facilities | Unsecured committed revolving credit facility | Third redemption date | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,300 | ||
NON-REGULATED | Corporate And Other - Credit Facilities | Unsecured non-revolving facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 30 |
Leases - Narrative (Details)
Leases - Narrative (Details) - Maximum | Dec. 31, 2020 |
Lessee, Lease, Description [Line Items] | |
Operating leases, remaining term (up to) | 21 years |
Finance leases, remaining term (up to) | 35 years |
Leases - Operating and Finance
Leases - Operating and Finance Lease Balance Sheet Location (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Operating leases | ||
Other assets | $ 40 | $ 46 |
Accounts payable and other current liabilities | $ (7) | (8) |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | us-gaap:OtherLiabilitiesNoncurrent | |
Other liabilities | $ (33) | (38) |
Finance leases | ||
Less: Current installments | (2) | (24) |
Finance leases | $ (331) | $ (413) |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent | us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent | us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent |
Springerville Common Facilities | TEP | ||
Finance leases | ||
Purchase of undivided interest (percent) | 32.20% | |
Regulatory assets | ||
Finance leases | ||
Finance lease assets | $ 122 | $ 116 |
PPE, net | ||
Finance leases | ||
Finance lease assets | $ 211 | $ 308 |
Leases - Lease Expenses (Detail
Leases - Lease Expenses (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | ||
Operating lease cost | $ 10 | $ 10 |
Finance lease cost: | ||
Amortization | 14 | 17 |
Interest | 34 | 48 |
Variable lease cost | 20 | 39 |
Total lease cost | $ 78 | $ 114 |
Leases - Present Value of Minim
Leases - Present Value of Minimum Lease Payments (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Operating Leases | ||
2021 | $ 8 | |
2022 | 7 | |
2023 | 6 | |
2024 | 4 | |
2025 | 3 | |
Thereafter | 22 | |
Total operating lease payments | 50 | |
Less: Imputed interest | (10) | |
Total lease obligations | 40 | |
Less: Current installments | (7) | $ (8) |
Operating leases | 33 | 38 |
Finance Leases | ||
2021 | 33 | |
2022 | 34 | |
2023 | 34 | |
2024 | 34 | |
2025 | 34 | |
Thereafter | 1,056 | |
Total finance lease payments | 1,225 | |
Less: Imputed interest | (892) | |
Total lease obligations | 333 | |
Less: Current installments | (2) | (24) |
Finance leases | 331 | $ 413 |
Total | ||
2021 | 41 | |
2022 | 41 | |
2023 | 40 | |
2024 | 38 | |
2025 | 37 | |
Thereafter | 1,078 | |
Total lease payments | 1,275 | |
Less: Imputed interest | (902) | |
Total lease obligations | 373 | |
Less: Current installments | (9) | |
Long-term lease obligations | $ 364 |
Leases - Supplemental Lease Inf
Leases - Supplemental Lease Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Weighted average remaining lease term (years) | ||
Operating leases | 10 years | 10 years |
Finance leases | 35 years | 27 years |
Weighted average discount rate (%) | ||
Operating leases | 4.00% | 4.10% |
Finance leases | 5.10% | 4.80% |
Cash payments related to lease liabilities | ||
Operating cash flows used for operating leases | $ (10) | $ (10) |
Operating cash flows used for finance leases | (2) | (47) |
Financing cash flows used for finance leases | (25) | (16) |
Investing cash flows used for finance leases | $ (87) | $ (212) |
Other Liabilities - Schedule of
Other Liabilities - Schedule of Other Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Other Liabilities Disclosure [Abstract] | ||
Employee future benefits (Note 25) | $ 905 | $ 832 |
Customer and other deposits | 132 | 70 |
AROs (Note 3) | 130 | 148 |
Stock-based compensation plans (Note 21) | 86 | 83 |
Manufactured gas plant site remediation | 69 | 48 |
Fair value of derivatives (Note 27) | 50 | 68 |
Mine reclamation obligations | 47 | 43 |
Retail energy contract | 46 | 0 |
Deferred compensation plan (Note 9) | 43 | 33 |
Operating leases | 33 | 38 |
Other | 58 | 83 |
Other liabilities | $ 1,599 | $ 1,446 |
Other Liabilities - Schedule _2
Other Liabilities - Schedule of Other Liabilities Footnotes (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2020CAD ($)mine | |
Central Hudson | |
Other Commitments [Line Items] | |
Remediation cost obligation | $ 96 |
Central Hudson | Accounts payable and other current liabilities | |
Other Commitments [Line Items] | |
Remediation cost obligation | $ 27 |
TEP | Coal mine reclamation | |
Other Commitments [Line Items] | |
Number of mines | mine | 2 |
Expected reclamation costs | $ 61 |
FortisAlberta | |
Other Commitments [Line Items] | |
Retail energy contract period | 8 years |
Common Shares (Details)
Common Shares (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2020CAD ($)shares | Dec. 31, 2019CAD ($)$ / sharesshares | Dec. 31, 2019USD ($)shares | |
Class of Stock [Line Items] | |||
Gross proceeds, net of commissions | $ 171 | $ 1,751 | |
2.10% Unsecured Notes | |||
Class of Stock [Line Items] | |||
Repayments of long-term debt | $ 500 | ||
Stated interest rate (percent) | 2.10% | ||
Common Shares | |||
Class of Stock [Line Items] | |||
Common shares issued (shares) | shares | 3.5 | 34.8 | 34.8 |
Gross proceeds, net of commissions | $ 174 | $ 1,756 | |
Common Shares | At-the-market | |||
Class of Stock [Line Items] | |||
Common shares issued (shares) | shares | 4.1 | 4.1 | |
Average price (CAD per share) | $ / shares | $ 52.16 | ||
Gross proceeds | $ 212 | ||
Gross proceeds, net of commissions | $ 209 | ||
Common Shares | Other Issuances | |||
Class of Stock [Line Items] | |||
Common shares issued (shares) | shares | 22.8 | 22.8 | |
Gross proceeds | $ 1,190 | ||
Gross proceeds, net of commissions | $ 1,167 | ||
Share price (CAD per share) | $ / shares | $ 52.15 |
Earnings Per Common Share (Deta
Earnings Per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Net Earnings to Common Shareholders | ||
Basic EPS | $ 1,209 | $ 1,655 |
Potential dilutive effect of stock options | 0 | 0 |
Diluted EPS | $ 1,209 | $ 1,655 |
Weighted Average Shares | ||
Basic EPS (shares) | 464.8 | 436.8 |
Potential dilutive effect of stock options (shares) | 0.6 | 0.7 |
Diluted EPS (shares) | 465.4 | 437.5 |
EPS | ||
Basic (CAD per share) | $ 2.60 | $ 3.79 |
Diluted (CAD per share) | $ 2.60 | $ 3.78 |
Preference Shares - Issued and
Preference Shares - Issued and outstanding (Details) - CAD ($) shares in Thousands, $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Class of Stock [Line Items] | ||
Preferred stock issued (shares) | 66,200 | 66,200 |
Preferred 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 issued (shares) | 5,000 | 5,000 |
Preferred 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 issued (shares) | 9,200 | 9,200 |
Preferred 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 issued (shares) | 7,665 | 7,025 |
Preferred stock issued | $ 188 | $ 172 |
Preferred stock outstanding (shares) | 7,665 | 7,025 |
Preferred stock outstanding | $ 188 | $ 172 |
Series I | ||
Class of Stock [Line Items] | ||
Preferred stock issued (shares) | 2,335 | 2,975 |
Preferred stock issued | $ 57 | $ 73 |
Preferred stock outstanding (shares) | 2,335 | 2,975 |
Preferred stock outstanding | $ 57 | $ 73 |
Series J | ||
Class of Stock [Line Items] | ||
Preferred stock issued (shares) | 8,000 | 8,000 |
Preferred 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 issued (shares) | 10,000 | 10,000 |
Preferred 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 issued (shares) | 24,000 | 24,000 |
Preferred 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) | 5 Months Ended | 12 Months Ended | 60 Months Ended | |
May 31, 2020$ / shares | Dec. 31, 2020$ / shares | May 31, 2025$ / shares | Dec. 01, 2021$ / 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 | |||
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) | $ 25.25 | |||
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 | |||
Reset Dividend Yield (percent) | 2.13% | |||
Redemption price (CAD per share) | $ 25 | |||
Series H | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.25% | |||
Annual Dividend (CAD per share) | $ 0.6250 | $ 0.4588 | ||
Reset Dividend Yield (percent) | 1.45% | |||
Redemption price (CAD per share) | $ 25 | |||
Preferred shares exchange ratio | 1 | |||
Series H | Forecast | ||||
Class of Stock [Line Items] | ||||
Annual Dividend (CAD per share) | $ 0.4588 | |||
Series K | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.00% | |||
Annual Dividend (CAD per share) | $ 0.9823 | |||
Reset Dividend Yield (percent) | 2.05% | |||
Redemption price (CAD per share) | $ 25 | |||
Preferred shares exchange ratio | 1 | |||
Series M | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.10% | |||
Annual Dividend (CAD per share) | $ 0.9783 | |||
Reset Dividend Yield (percent) | 2.48% | |||
Redemption price (CAD per share) | $ 25 | |||
Preferred shares exchange ratio | 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 | |||
Preferred shares exchange ratio | 1 | |||
Series L | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 0.00% | |||
Annual Dividend (CAD per share) | $ 0 | |||
Reset Dividend Yield (percent) | 0.00% | |||
Redemption price (CAD per share) | $ 0 | |||
Preferred shares exchange ratio | 1 | |||
Series N | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 0.00% | |||
Annual Dividend (CAD per share) | $ 0 | |||
Reset Dividend Yield (percent) | 0.00% | |||
Redemption price (CAD per share) | $ 0 | |||
Preferred shares exchange ratio | 1 | |||
Fixed rate reset | ||||
Class of Stock [Line Items] | ||||
Redemption price (CAD per share) | $ 25 |
Preference Shares - Conversion
Preference Shares - Conversion of stock (Details) | Jun. 01, 2020shares |
First Preference Shares, Series H | |
Conversion of Stock [Line Items] | |
Number of shares converted (in shares) | 267,341 |
Number of shares issued for each share of convertible preferred stock (in shares) | 1 |
First Preference Shares, Series I | |
Conversion of Stock [Line Items] | |
Number of shares converted (in shares) | 907,577 |
Number of shares issued for each share of convertible preferred stock (in shares) | 1 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Accumulated other comprehensive income | ||
Beginning balance | $ 18,531 | |
Ending balance | 18,697 | $ 18,531 |
Net investments in foreign operations | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | 713 | 1,470 |
Other comprehensive income (loss), before tax | (336) | (757) |
Accumulated other comprehensive income (loss), before tax, ending balance | 377 | 713 |
Hedges of net investments in foreign operations | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (359) | (544) |
Other comprehensive income (loss), before tax | 60 | 185 |
Accumulated other comprehensive income (loss), before tax, ending balance | (299) | (359) |
Net unrealized foreign currency translation gains (losses) | ||
Accumulated other comprehensive income | ||
Income tax recovery (expense), opening balance | (3) | 10 |
Beginning balance | 351 | 936 |
Other comprehensive income (loss), tax recovery (expense) | (3) | (13) |
Other comprehensive income (loss) | (279) | (585) |
Income tax recovery (expense), ending balance | (6) | (3) |
Ending balance | 72 | 351 |
Cash flow hedges (Note 28) | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | 17 | 11 |
Other comprehensive income (loss), before tax | (21) | 6 |
Accumulated other comprehensive income (loss), before tax, ending balance | (4) | 17 |
Unrealized employee future benefits losses (Note 25) | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (38) | (20) |
Other comprehensive income (loss), before tax | (11) | (18) |
Accumulated other comprehensive income (loss), before tax, ending balance | (49) | (38) |
Cash flow hedges and unrealized employee future benefits (losses) gains | ||
Accumulated other comprehensive income | ||
Income tax recovery (expense), opening balance | 6 | 1 |
Beginning balance | (15) | (8) |
Other comprehensive income (loss), tax recovery (expense) | 9 | 5 |
Other comprehensive income (loss) | (23) | (7) |
Income tax recovery (expense), ending balance | 15 | 6 |
Ending balance | (38) | (15) |
Accumulated other comprehensive income | ||
Accumulated other comprehensive income | ||
Beginning balance | 336 | 928 |
Other comprehensive income (loss) | (302) | (592) |
Ending balance | $ 34 | $ 336 |
Stock-based Compensation Plan_2
Stock-based Compensation Plans - Stock Options Narrative (Details) - Options | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Exercisable period | 10 years |
Expiration period after 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 | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Options granted (shares) | 686,000 | 852,000 |
Exercise price (CAD per share) | $ 58.40 | $ 47.57 |
Grant date fair value (CAD per share) | $ 4.20 | $ 3.70 |
Options | ||
Valuation assumptions: | ||
Dividend yield (percent) | 3.70% | 3.80% |
Expected volatility (percent) | 15.80% | 15.20% |
Risk-free interest rate | 1.20% | 1.80% |
Weighted average expected life (years) | 5 years 2 months 12 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 | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Total Options, Number of Options | ||
Options outstanding, beginning balance (shares) | 3,418,000 | |
Granted (shares) | 686,000 | 852,000 |
Exercised (shares) | (825,000) | |
Cancelled/Forfeited (shares) | (17,000) | |
Options outstanding, ending balance (shares) | 3,262,000 | 3,418,000 |
Options vested, number of options (shares) | 1,490,000 | |
Total Options, Weighted Average Exercise Price | ||
Options outstanding, beginning balance (CAD per share) | $ 41.18 | |
Granted (CAD per share) | 58.40 | $ 47.57 |
Exercised (CAD per share) | 39.21 | |
Cancelled/Forfeited (CAD per share) | 50.02 | |
Options outstanding, ending balance (CAD per share) | 45.26 | $ 41.18 |
Options vested, weighted average exercise price (CAD per share) | $ 39.40 | |
Non-vested Options, Number of Options | ||
Options outstanding, beginning balance (shares) | 1,910,000 | |
Granted (shares) | 686,000 | 852,000 |
Vested (shares) | (807,000) | |
Cancelled/Forfeited (shares) | (17,000) | |
Options outstanding, ending balance (shares) | 1,772,000 | 1,910,000 |
Non-vested Options, Weighted Average Grant Date Fair Value | ||
Options outstanding, beginning balance (CAD per share) | $ 3.43 | |
Granted (CAD per share) | 4.20 | $ 3.70 |
Vested (CAD per share) | 3.25 | |
Cancelled/Forfeited (CAD per share) | 3.79 | |
Options outstanding, ending balance (CAD per share) | $ 3.81 | $ 3.43 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unrecognized compensation expense | $ 7 | |
Weighted average remaining term of vested options | 6 years | |
Aggregate intrinsic value of vested options | $ 19 | |
Options | ||
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, 2020 | Dec. 31, 2019 | |
Stock options exercised: | ||
Cash received for exercise price | $ 32 | $ 51 |
Intrinsic value realized by employees | $ 15 | $ 22 |
Stock-based Compensation Plan_6
Stock-based Compensation Plans - Directors' DSU Plan (Details) - Director - DSUs | 12 Months Ended | |
Dec. 31, 2020shares | Dec. 31, 2019shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unit with underlying value equivalent to common shares | 1 | |
Number of units (in thousands) | ||
DSUs outstanding, beginning of year (shares) | 165,000 | 177,000 |
Granted (shares) | 25,000 | 29,000 |
Granted - notional dividends reinvested (shares) | 6,000 | 6,000 |
Paid out (shares) | (49,000) | (47,000) |
DSUs outstanding, end of year (shares) | 147,000 | 165,000 |
Stock-based Compensation Plan_7
Stock-based Compensation Plans - PSU Plans Narrative (Details) - PSUs | 12 Months Ended |
Dec. 31, 2020 | |
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 ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
PSUs | ||
Number of units (in thousands) | ||
Outstanding, beginning of year (shares) | 2,118,000 | 1,763,000 |
Granted (shares) | 586,000 | 690,000 |
Notional dividends reinvested (shares) | 71,000 | 73,000 |
Paid out (shares) | (735,000) | (357,000) |
Cancelled/forfeited (shares) | (64,000) | (51,000) |
Outstanding, end of year (shares) | 1,976,000 | 2,118,000 |
Additional information (in millions) | ||
Compensation expense recognized | $ 58 | $ 74 |
Compensation expense unrecognized | 32 | 35 |
Cash payout | 54 | 16 |
Accrued liability as at December 31 | 108 | 106 |
Aggregate intrinsic value as at December 31 | $ 140 | $ 141 |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Weighted-average contractual life (years) | 1 year | |
RSUs | ||
Number of units (in thousands) | ||
Outstanding, beginning of year (shares) | 1,050,000 | 717,000 |
Granted (shares) | 356,000 | 429,000 |
Notional dividends reinvested (shares) | 37,000 | 35,000 |
Paid out (shares) | (355,000) | (92,000) |
Cancelled/forfeited (shares) | (40,000) | (39,000) |
Outstanding, end of year (shares) | 1,048,000 | 1,050,000 |
Additional information (in millions) | ||
Compensation expense recognized | $ 20 | $ 24 |
Compensation expense unrecognized | 15 | 17 |
Cash payout | 19 | 4 |
Accrued liability as at December 31 | 39 | 39 |
Aggregate intrinsic value as at December 31 | $ 54 | $ 56 |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Weighted-average contractual life (years) | 1 year |
Stock-based Compensation Plan_9
Stock-based Compensation Plans - RSU Plans Narrative (Details) - RSUs | 12 Months Ended |
Dec. 31, 2020 | |
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 |
Disposition (Details)
Disposition (Details) $ in Millions | Apr. 16, 2019CAD ($)MW | Apr. 16, 2019CAD ($)MW | Dec. 31, 2020CAD ($) | Dec. 31, 2019CAD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Gain on disposition | $ 0 | $ 577 | ||
Waneta Expansion | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Ownership percentage sold | 51.00% | |||
Fortis' share of earnings before tax, excluding the gain on disposition | 51.00% | |||
Waneta Expansion | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Generating capacity (MW) | MW | 335 | 335 | ||
Proceeds on disposition | $ 995 | $ 995 | ||
Gain on disposition | 577 | |||
Gain on disposition, after tax | $ 484 | |||
Earnings before tax, excluding the gain on disposition | $ 17 |
Other Income, Net (Details)
Other Income, Net (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | ||
Equity component of AFUDC | $ 78 | $ 74 |
Equity income | 20 | (1) |
Derivative gains | 13 | 17 |
Interest income | 13 | 16 |
Gain on repayment of debt | 0 | 11 |
Other | 30 | 21 |
Other income, net | $ 154 | $ 138 |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Income Tax Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Gross deferred income tax assets | ||
Regulatory liabilities | $ 527 | $ 588 |
Tax loss and credit carryforwards | 494 | 532 |
Employee future benefits | 175 | 165 |
Unrealized foreign exchange losses on long-term debt | 33 | 40 |
Other | 83 | 88 |
Deferred tax assets, gross | 1,312 | 1,413 |
Valuation allowance | (22) | (22) |
Net deferred income tax asset | 1,290 | 1,391 |
Gross deferred income tax liabilities | ||
PPE | (4,253) | (3,986) |
Regulatory assets | (263) | (269) |
Intangible assets | (118) | (105) |
Deferred tax liabilities, gross | (4,634) | (4,360) |
Net deferred income tax liability | $ (3,344) | $ (2,969) |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | ||
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, 2020 | Dec. 31, 2019 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning of year | $ 36 | $ 38 |
Additions related to current year | 3 | 5 |
Adjustments related to prior years | (6) | (7) |
End of year | $ 33 | $ 36 |
Income Taxes - Schedule of Comp
Income Taxes - Schedule of Components of Income Tax Expense (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Canadian | ||
Earnings before income tax expense | $ 333 | $ 901 |
Current income tax | 20 | 49 |
Deferred income tax | (16) | 42 |
Total Canadian | 4 | 91 |
Foreign | ||
Earnings before income tax expense | 1,287 | 1,240 |
Current income tax | (15) | (7) |
Deferred income tax | 242 | 205 |
Total Foreign | 227 | 198 |
Income tax expense | $ 231 | $ 289 |
Income Taxes - Schedule of Effe
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | ||
Earnings before income tax expense | $ 1,620 | $ 2,141 |
Combined Canadian federal and provincial statutory income tax rate (%) | 30.00% | 28.50% |
Expected federal and provincial taxes at statutory rate | $ 486 | $ 610 |
Expected federal and provincial taxes at statutory rate Increase (decrease) resulting from: | ||
Foreign and other statutory rate differentials | (145) | (124) |
Difference between gain on sale for accounting and amounts calculated for tax purposes | 0 | (73) |
Release of valuation allowance | 0 | (33) |
AFUDC | (20) | (16) |
Effects of rate-regulated accounting: | ||
Difference between depreciation claimed for income tax and accounting purposes | (56) | (48) |
Items capitalized for accounting purposes but expensed for income tax purposes | (26) | (17) |
Other | (8) | (10) |
Income tax expense | $ 231 | $ 289 |
Effective tax rate (%) | 14.30% | 13.50% |
Income Taxes - Tax Carryforward
Income Taxes - Tax Carryforward (Details) $ in Millions | Dec. 31, 2020CAD ($) |
Tax Credit Carryforward [Line Items] | |
Total income tax carryforwards recognized | $ 3,208 |
Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax carryforward, gross | 229 |
Unrecognized | (26) |
Total income tax carryforwards recognized | 203 |
Foreign | |
Tax Credit Carryforward [Line Items] | |
Federal and state net operating loss | 2,971 |
Tax carryforward, gross | 3,005 |
Capital loss | Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | 27 |
Non-capital loss | Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | 200 |
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 | $ 34 |
Employee Future Benefits - Sche
Employee Future Benefits - Schedule of Allocation of and Fair Value of Plan Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Defined Benefit Plan Disclosure [Line Items] | |||
2020 Target Allocation | 100.00% | ||
Actual Plan Asset Allocations (percent) | 100.00% | 100.00% | |
Fair value of plan assets | $ 3,919 | $ 3,551 | |
Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2020 Target Allocation | 46.00% | ||
Actual Plan Asset Allocations (percent) | 48.00% | 47.00% | |
Fair value of plan assets | $ 1,876 | $ 1,672 | |
Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2020 Target Allocation | 47.00% | ||
Actual Plan Asset Allocations (percent) | 45.00% | 46.00% | |
Fair value of plan assets | $ 1,777 | $ 1,616 | |
Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2020 Target Allocation | 6.00% | ||
Actual Plan Asset Allocations (percent) | 6.00% | 6.00% | |
Fair value of plan assets | $ 221 | $ 223 | |
Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 20 | $ 22 | |
Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2020 Target Allocation | 1.00% | ||
Actual Plan Asset Allocations (percent) | 1.00% | 1.00% | |
Fair value of plan assets | $ 25 | $ 18 | |
Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 918 | 801 | |
Level 1 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 713 | 622 | |
Level 1 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 197 | 171 | |
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 | 2,777 | 2,521 | |
Level 2 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,163 | 1,050 | |
Level 2 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,580 | 1,445 | |
Level 2 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 17 | 16 | |
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 | 17 | 10 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 224 | 229 | $ 215 |
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 | 204 | 207 | |
Level 3 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 20 | 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, 2020 | Dec. 31, 2019 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | $ 3,551 | |
Balance, end of year | 3,919 | $ 3,551 |
Level 3 | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | 229 | 215 |
(Loss) return on plan assets | (2) | 19 |
Foreign currency translation | (1) | (2) |
Purchases, sales and settlements | (2) | (3) |
Balance, end of year | $ 224 | $ 229 |
Employee Future Benefits - Sc_3
Employee Future Benefits - Schedule of Funded Status (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Change in value of plan assets | ||
Balance, beginning of year | $ 3,551 | |
Balance, end of year | 3,919 | $ 3,551 |
Long-term assets (Note 9) | 66 | 63 |
Long-term liabilities (Note 16) | (905) | (832) |
Defined Benefit Pension Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 3,632 | 3,207 |
Service costs | 98 | 77 |
Employee contributions | 17 | 16 |
Interest costs | 113 | 124 |
Benefits paid | (162) | (144) |
Actuarial losses | 350 | 439 |
Past service (credits) costs/plan amendments | 0 | 1 |
Foreign currency translation | (53) | (88) |
Balance, end of year | 3,995 | 3,632 |
Change in value of plan assets | ||
Balance, beginning of year | 3,208 | 2,830 |
Actual return on plan assets | 444 | 523 |
Benefits paid | (155) | (138) |
Employee contributions | 17 | 18 |
Employer contributions | 62 | 53 |
Foreign currency translation | (48) | (78) |
Balance, end of year | 3,528 | 3,208 |
Funded status | (467) | (424) |
Long-term assets (Note 9) | 58 | 46 |
Current liabilities (Note 13) | (13) | (12) |
Long-term liabilities (Note 16) | (512) | (458) |
Net liabilities | (467) | (424) |
Accumulated benefit obligation | 3,679 | 3,352 |
OPEB Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 712 | 655 |
Service costs | 32 | 27 |
Employee contributions | 2 | 2 |
Interest costs | 22 | 25 |
Benefits paid | (27) | (27) |
Actuarial losses | 62 | 46 |
Past service (credits) costs/plan amendments | (3) | 4 |
Foreign currency translation | (11) | (20) |
Balance, end of year | 789 | 712 |
Change in value of plan assets | ||
Balance, beginning of year | 343 | 293 |
Actual return on plan assets | 55 | 62 |
Benefits paid | (27) | (27) |
Employee contributions | 2 | 2 |
Employer contributions | 28 | 28 |
Foreign currency translation | (10) | (15) |
Balance, end of year | 391 | 343 |
Funded status | (398) | (369) |
Long-term assets (Note 9) | 8 | 17 |
Current liabilities (Note 13) | (13) | (12) |
Long-term liabilities (Note 16) | (393) | (374) |
Net liabilities | $ (398) | $ (369) |
Employee Future Benefits - Summ
Employee Future Benefits - Summary of Benefit Obligations and Fair Value Narrative (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected benefit obligation | $ 3,290 | $ 2,971 |
Plan with projected benefit obligation, fair value of plan assets | 2,777 | 2,511 |
Accumulated benefit obligation | 3,037 | 2,752 |
Plan with accumulated benefit obligation, fair value of plan assets | 2,741 | 2,478 |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | 589 | 537 |
Plan with accumulated benefit obligation, fair value of plan assets | $ 183 | $ 151 |
Employee Future Benefits - Sc_4
Employee Future Benefits - Schedule of Net Benefit Costs (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | $ 98 | $ 77 |
Interest costs | 113 | 124 |
Expected return on plan assets | (176) | (161) |
Amortization of actuarial losses (gains) | 33 | 24 |
Amortization of past service credits/plan amendments | (1) | (1) |
Regulatory adjustments | 0 | 2 |
Net Benefit Cost | 67 | 65 |
OPEB Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | 32 | 27 |
Interest costs | 22 | 25 |
Expected return on plan assets | (19) | (16) |
Amortization of actuarial losses (gains) | (5) | (4) |
Amortization of past service credits/plan amendments | (2) | (7) |
Regulatory adjustments | 4 | 3 |
Net Benefit Cost | $ 32 | $ 28 |
Employee Future Benefits - Comp
Employee Future Benefits - Components of AOCI and Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Regulatory assets (Note 8) | $ 3,588 | $ 3,383 |
Regulatory liabilities (Note 8) | (3,103) | (3,358) |
Defined Benefit Pension Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses (gains) | 42 | 32 |
Unamortized past service costs | 1 | 1 |
Income tax recovery | (10) | (8) |
Accumulated other comprehensive income | 33 | 25 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses (gains) | 517 | 486 |
Past service credits | (7) | (9) |
Other regulatory deferrals | 13 | 15 |
Net regulatory assets (liabilities) | 523 | 492 |
Regulatory assets (Note 8) | 523 | 492 |
Regulatory liabilities (Note 8) | 0 | 0 |
OPEB Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses (gains) | (1) | (2) |
Unamortized past service costs | 7 | 7 |
Income tax recovery | (1) | (1) |
Accumulated other comprehensive income | 5 | 4 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses (gains) | 12 | (18) |
Past service credits | (8) | (8) |
Other regulatory deferrals | 18 | 19 |
Net regulatory assets (liabilities) | 22 | (7) |
Regulatory assets (Note 8) | 65 | 38 |
Regulatory liabilities (Note 8) | $ (43) | $ (45) |
Employee Future Benefits - Co_2
Employee Future Benefits - Components Recognized in OCI and Regulatory Assets (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial losses | $ 9 | $ 11 |
Past service costs/plan amendments | 0 | 0 |
Amortization of actuarial losses | 1 | 1 |
Foreign currency translation | 0 | 1 |
Income tax recovery | (2) | (5) |
Total recognized in comprehensive income | 8 | 8 |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Current year net actuarial losses | 69 | 64 |
Past service costs (credits)/plan amendments | 0 | 0 |
Amortization of actuarial (losses) gains | (31) | (23) |
Amortization of past service (costs) credits | 2 | (1) |
Foreign currency translation | (7) | (10) |
Regulatory adjustments | (2) | 0 |
Total recognized in regulatory assets | 31 | 30 |
OPEB Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial losses | 1 | 0 |
Past service costs/plan amendments | 0 | 5 |
Amortization of actuarial losses | 0 | 0 |
Foreign currency translation | 0 | 0 |
Income tax recovery | 0 | 0 |
Total recognized in comprehensive income | 1 | 5 |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Current year net actuarial losses | 25 | 3 |
Past service costs (credits)/plan amendments | (3) | 0 |
Amortization of actuarial (losses) gains | 5 | 4 |
Amortization of past service (costs) credits | 3 | 8 |
Foreign currency translation | 0 | 0 |
Regulatory adjustments | (1) | (8) |
Total recognized in regulatory assets | $ 29 | $ 7 |
Employee Future Benefits - Sc_5
Employee Future Benefits - Schedule of Assumptions Used (Details) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 3.16% | 4.05% |
Discount rate as at December 31 | 2.63% | 3.20% |
Expected long-term rate of return on plan assets | 5.52% | 5.78% |
Rate of compensation increase | 3.34% | 3.33% |
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 | 3.22% | 4.10% |
Discount rate as at December 31 | 2.64% | 3.25% |
Expected long-term rate of return on plan assets | 5.28% | 5.50% |
Rate of compensation increase | 0.00% | 0.00% |
Health care cost trend increase as at December 31 | 4.61% | 4.62% |
Health care cost trend rate assumed for next fiscal year | 5.91% | |
Remaining period until health care cost trend rate reaches ultimate trend rate | 11 years |
Employee Future Benefits - Sc_6
Employee Future Benefits - Schedule of Expected Benefit Payments (Details) $ in Millions | Dec. 31, 2020CAD ($) |
Defined Benefit Pension Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2021 | $ 163 |
2022 | 165 |
2023 | 170 |
2024 | 174 |
2025 | 180 |
2026-2030 | 984 |
OPEB Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2021 | 27 |
2022 | 28 |
2023 | 30 |
2024 | 31 |
2025 | 32 |
2026-2030 | $ 174 |
Employee Future Benefits - Defi
Employee Future Benefits - Defined Contribution Plan Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Defined contribution plan cost recognized | $ 42 | $ 39 |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Expected contributions for next fiscal year | 49 | |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Expected contributions for next fiscal year | $ 33 |
Supplementary Cash Flow Infor_3
Supplementary Cash Flow Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Cash paid (received) for | ||
Interest | $ 1,027 | $ 1,007 |
Income taxes | (26) | (37) |
Change in working capital | ||
Accounts receivable and other current assets | (84) | 1 |
Prepaid expenses | (15) | (8) |
Inventories | (36) | (13) |
Regulatory assets - current portion | (49) | (75) |
Accounts payable and other current liabilities | (100) | (8) |
Regulatory liabilities - current portion | (150) | (65) |
Change in working capital | (434) | (168) |
Non-cash investing and financing activities | ||
Accrued capital expenditures | 400 | 382 |
Common share dividends reinvested | 114 | 299 |
Contributions in aid of construction | 13 | 15 |
Right-of-use assets obtained in exchange for operating lease liabilities | 3 | 55 |
Exercise of stock options into common shares | 3 | 5 |
Finance leases | $ 2 | $ 88 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments and Risk Management - Derivatives Narrative (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | ||
May 31, 2020CAD ($) | Dec. 31, 2020CAD ($) | May 31, 2020USD ($) | Dec. 31, 2019CAD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Regulatory assets | $ 3,588 | $ 3,383 | ||
Regulatory liability | $ 3,103 | 3,358 | ||
UNS Energy | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Realized gains shared with customers, percent | 10.00% | |||
ITC | Unsecured | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Face value | $ 700 | |||
Energy contracts subject to regulatory deferral | Derivative instruments | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Regulatory liability | $ 17 | 2 | ||
Energy contracts subject to regulatory deferral | Derivative instruments | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Regulatory assets | 73 | $ 119 | ||
Total return swaps | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Notional amount of derivative | $ 113 | |||
Total return swaps | Minimum | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative terms | 1 year | |||
Total return swaps | Maximum | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative terms | 3 years | |||
Foreign exchange contracts | Not designated as hedging instrument | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Notional amount of derivative | $ 245 | |||
Interest rate swaps | ITC | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Notional amount of derivative | $ 611 | |||
Realized loss on derivative | $ 31 | |||
Reclassification period | 5 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, 2020 | Dec. 31, 2019 |
Assets | ||
Other investments | $ 126 | $ 121 |
Assets, total fair value | 186 | 169 |
Liabilities | ||
Liabilities, total fair value | (106) | (151) |
Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 38 | 22 |
Liabilities | ||
Liabilities | (94) | (139) |
Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 6 | 8 |
Liabilities | ||
Liabilities | (12) | (12) |
Foreign Exchange Contracts And Total Return Swaps | ||
Assets | ||
Assets | 16 | |
Foreign Exchange Contracts, Interest Rate and Total Return Swaps | ||
Assets | ||
Assets | 18 | |
Level 1 | ||
Assets | ||
Other investments | 126 | 121 |
Assets, total fair value | 142 | 135 |
Liabilities | ||
Liabilities, total fair value | 0 | (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 And Total Return Swaps | ||
Assets | ||
Assets | 16 | |
Level 1 | Foreign Exchange Contracts, Interest Rate and Total Return Swaps | ||
Assets | ||
Assets | 14 | |
Level 2 | ||
Assets | ||
Other investments | 0 | 0 |
Assets, total fair value | 44 | 34 |
Liabilities | ||
Liabilities, total fair value | (106) | (150) |
Level 2 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 38 | 22 |
Liabilities | ||
Liabilities | (94) | (138) |
Level 2 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 6 | 8 |
Liabilities | ||
Liabilities | (12) | (12) |
Level 2 | Foreign Exchange Contracts And Total Return Swaps | ||
Assets | ||
Assets | 0 | |
Level 2 | Foreign Exchange Contracts, Interest Rate and Total Return Swaps | ||
Assets | ||
Assets | 4 | |
Level 3 | ||
Assets | ||
Other investments | 0 | 0 |
Assets, total fair value | 0 | 0 |
Liabilities | ||
Liabilities, total fair value | 0 | 0 |
Level 3 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | 0 |
Level 3 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | 0 |
Level 3 | Foreign Exchange Contracts And Total Return Swaps | ||
Assets | ||
Assets | $ 0 | |
Level 3 | Foreign Exchange Contracts, Interest Rate and Total Return Swaps | ||
Assets | ||
Assets | $ 0 |
Fair Value of Financial Instr_5
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, 2020 | Dec. 31, 2019 |
Derivative assets | ||
Gross Amount Recognized in Balance Sheet | $ 44 | $ 30 |
Counterparty Netting of Energy Contracts | 26 | 22 |
Cash Collateral Received/Posted | 10 | 10 |
Net Amount | 8 | (2) |
Derivative liabilities | ||
Gross Amount Recognized in Balance Sheet | (106) | (151) |
Counterparty Netting of Energy Contracts | (26) | (22) |
Cash Collateral Received/Posted | (9) | (2) |
Net Amount | $ (71) | $ (127) |
Fair Value of Financial Instr_6
Fair Value of Financial Instruments and Risk Management - Volume of Derivative Activity (Details) kJ in Trillions | 12 Months Ended | |
Dec. 31, 2020kJGWh | Dec. 31, 2019kJGWh | |
Electricity swap contracts, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 522 | 628 |
Electricity power purchase contracts, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 2,781 | 3,198 |
Gas swap contracts, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | kJ | 156 | 168 |
Gas supply contract premiums, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | kJ | 203 | 241 |
Wholesale trading contracts, Energy contracts not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 1,588 | 1,855 |
Gas swap contracts, Energy contracts not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | kJ | 36 | 43 |
Fair Value of Financial Instr_7
Fair Value of Financial Instruments and Risk Management - Credit Risk Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value, Concentration Risk, Financial Statement Captions [Line Items] | ||
Value of derivative instruments in net liability positions | $ 88 | $ 161 |
Revenue | Three customers | Customer Concentration Risk | ITC | ||
Fair Value, Concentration Risk, Financial Statement Captions [Line Items] | ||
Concentration risk percentage | 70.00% |
Fair Value of Financial Instr_8
Fair Value of Financial Instruments and Risk Management - Foreign Exchange Hedge Narrative (Details) - Foreign net investments - USD ($) $ in Billions | Dec. 31, 2020 | Dec. 31, 2019 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Unhedged foreign net investments | $ 10.2 | $ 9.7 |
Designated as hedging instrument | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Long-term debt designated as an effective hedge | $ 2.3 | $ 2.2 |
Fair Value of Financial Instr_9
Fair Value of Financial Instruments and Risk Management - Financial Instruments Not Carried At Fair Value Narrative (Details) - CAD ($) $ in Billions | Dec. 31, 2020 | Dec. 31, 2019 |
Carrying Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion | $ 24.5 | $ 22.3 |
Estimated Fair Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion | $ 29.1 | $ 25.3 |
Commitments and Contingencies -
Commitments and Contingencies - Fiscal Year Maturity (Details) $ in Millions | Dec. 31, 2020CAD ($) |
Purchase obligations: | |
Total | $ 8,884 |
Year 1 | 1,161 |
Year 2 | 851 |
Year 3 | 691 |
Year 4 | 568 |
Year 5 | 487 |
Thereafter | 5,126 |
Waneta Expansion capacity agreement | |
Purchase obligations: | |
Total | 2,576 |
Year 1 | 52 |
Year 2 | 53 |
Year 3 | 54 |
Year 4 | 55 |
Year 5 | 56 |
Thereafter | 2,306 |
Gas and fuel purchase obligations | |
Purchase obligations: | |
Total | 2,355 |
Year 1 | 679 |
Year 2 | 453 |
Year 3 | 312 |
Year 4 | 192 |
Year 5 | 124 |
Thereafter | 595 |
Power purchase obligations | |
Purchase obligations: | |
Total | 1,867 |
Year 1 | 249 |
Year 2 | 208 |
Year 3 | 188 |
Year 4 | 191 |
Year 5 | 180 |
Thereafter | 851 |
Renewable PPAs | |
Purchase obligations: | |
Total | 1,380 |
Year 1 | 102 |
Year 2 | 102 |
Year 3 | 101 |
Year 4 | 101 |
Year 5 | 101 |
Thereafter | 873 |
ITC easement agreement | |
Purchase obligations: | |
Total | 381 |
Year 1 | 13 |
Year 2 | 13 |
Year 3 | 13 |
Year 4 | 13 |
Year 5 | 13 |
Thereafter | 316 |
Debt collection agreement | |
Purchase obligations: | |
Total | 112 |
Year 1 | 3 |
Year 2 | 3 |
Year 3 | 3 |
Year 4 | 3 |
Year 5 | 3 |
Thereafter | 97 |
Renewable energy credit purchase agreement | |
Purchase obligations: | |
Total | 97 |
Year 1 | 15 |
Year 2 | 14 |
Year 3 | 16 |
Year 4 | 9 |
Year 5 | 7 |
Thereafter | 36 |
Other | |
Purchase obligations: | |
Total | 116 |
Year 1 | 48 |
Year 2 | 5 |
Year 3 | 4 |
Year 4 | 4 |
Year 5 | 3 |
Thereafter | $ 52 |
Commitments and Contingencies_2
Commitments and Contingencies - Fiscal Year Maturity (Footnotes) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Apr. 30, 2015 | Dec. 31, 2020CAD ($)GWhagreement_renewalcontractMW | Jan. 01, 2021CAD ($) | |
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 8,884 | ||
Waneta Expansion capacity agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | 2,576 | ||
Waneta Expansion capacity agreement | FortisBC Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase commitment term | 40 years | ||
Gas and fuel purchase obligations | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | 2,355 | ||
Gas and fuel purchase obligations | FortisBC Energy | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | 1,482 | ||
Gas and fuel purchase obligations | UNS Energy | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | 747 | ||
Power purchase and capacity | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 1,867 | ||
Power purchase and capacity | FortisBC Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase commitment term | 20 years | ||
Purchase obligation | $ 295 | ||
Power purchase and capacity | 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 | ||
Power purchase and capacity | Maritime Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 910 | ||
Number of long-term take-or-pay contracts | contract | 2 | ||
Power purchase and capacity | Maritime Electric | Nuclear Generating Station | |||
Long-term Purchase Commitment [Line Items] | |||
Share of plant output, percentage | 4.55% | ||
Power purchase and capacity | FortisOntario | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 599 | ||
Power purchase and capacity | FortisOntario | Maximum | |||
Long-term Purchase Commitment [Line Items] | |||
Amount of volume required (in mw) | MW | 145 | ||
Power purchase and capacity | FortisOntario | Minimum | |||
Long-term Purchase Commitment [Line Items] | |||
Volume of energy required to be purchased (in GWh) | GWh | 537 | ||
Renewable Power | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 1,380 | ||
Renewable Power | TEP and UNS Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase commitment, percentage | 100.00% | ||
ITC easement agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 381 | ||
ITC easement agreement | ITC | |||
Long-term Purchase Commitment [Line Items] | |||
Number of agreement renewals | agreement_renewal | 10 | ||
Agreement renewal term | 50 years | ||
Notice, period in advance | 1 year | ||
Other | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 116 | ||
Other | UNS Energy | Forecast | |||
Long-term Purchase Commitment [Line Items] | |||
Purchase obligation | $ 24 |
Commitments and Contingencies_3
Commitments and Contingencies - Other Commitments Narrative (Details) | 12 Months Ended |
Dec. 31, 2020CAD ($) | |
Wataynikaneyap Partnership | |
Other Commitments [Line Items] | |
Equity investment ownership (percent) | 39.00% |
Wataynikaneyap Partnership | Minimum | |
Other Commitments [Line Items] | |
Equity capital contribution | $ 155,000,000 |
Wataynikaneyap Partnership | Maximum | |
Other Commitments [Line Items] | |
Equity capital contribution | 235,000,000 |
UNS Energy | Payment Guarantee | |
Other Commitments [Line Items] | |
Maximum commitment | 318,000,000 |
Obligation under guarantee | 0 |
CH Energy Group | Payment Guarantee | |
Other Commitments [Line Items] | |
Maximum commitment | 94,000,000 |
Obligation under guarantee | 0 |
FHI | Indirect Guarantee of Indebtedness | |
Other Commitments [Line Items] | |
Maximum commitment | $ 69,000,000 |
Commitments and Contingencies_4
Commitments and Contingencies - Contingency Narrative (Details) | Dec. 31, 2020CAD ($) |
Claim related to pipeline rights | FHI and Fortis | |
Other Commitments [Line Items] | |
Contingency accrual | $ 0 |