Cover page
Cover page | 12 Months Ended |
Dec. 31, 2022 shares | |
Document Information [Line Items] | |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Current Fiscal Year End Date | --12-31 |
Document Period End Date | Dec. 31, 2022 |
Entity File Number | 001-37915 |
Entity Registrant Name | FORTIS INC. |
Entity Incorporation, State or Country Code | A4 |
Entity Primary SIC Number | 4911 |
Entity Tax Identification Number | 98-0352146 |
Entity Address, Address Line Three | Fortis Place |
Entity Address, Address Line Two | Suite 1100 |
Entity Address, Address Line One | 5 Springdale Street |
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 Common Stock, Shares Outstanding | 482,150,634 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
ICFR Auditor Attestation Flag | true |
Entity Central Index Key | 0001666175 |
Document Fiscal Year Focus | 2022 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Business Contact | |
Document Information [Line Items] | |
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 |
Contact Personnel Name | James R. Reid |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Firm ID | 1208 |
Auditor Name | Deloitte LLP |
Auditor Location | St. John's, Canada |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Current assets | |||
Cash and cash equivalents | $ 209 | $ 131 | |
Accounts receivable and other current assets (Note 6) | 2,339 | 1,511 | |
Prepaid expenses | 146 | 116 | |
Inventories (Note 7) | 661 | 478 | |
Regulatory assets (Note 8) | 914 | 492 | |
Total current assets | 4,269 | 2,728 | |
Other assets (Note 9) | 1,213 | 955 | |
Regulatory assets (Note 8) | 3,095 | 3,097 | |
Property, plant and equipment, net (Note 10) | 41,663 | 37,816 | |
Intangible assets, net (Note 11) | 1,548 | 1,343 | |
Goodwill (Note 12) | 12,464 | 11,720 | |
Total assets | 64,252 | 57,659 | |
Current liabilities | |||
Short-term borrowings (Note 14) | 253 | 247 | |
Accounts payable and other current liabilities (Note 13) | 3,288 | 2,570 | |
Regulatory liabilities (Note 8) | 595 | 357 | |
Current installments of long-term debt (Note 14) | 2,481 | 1,628 | |
Total current liabilities | 6,617 | 4,802 | |
Regulatory liabilities (Note 8) | 3,320 | 2,865 | |
Deferred income taxes (Note 22) | 4,060 | 3,627 | |
Long-term debt (Note 14) | 25,931 | 23,707 | |
Finance leases (Note 15) | 336 | 333 | |
Other liabilities (Note 16) | 1,146 | 1,409 | |
Total liabilities | 41,410 | 36,743 | |
Commitments and contingencies (Note 26) | |||
Equity | |||
Common shares | [1] | 14,656 | 14,237 |
Preference shares (Note 18) | 1,623 | 1,623 | |
Additional paid-in capital | 10 | 10 | |
Accumulated other comprehensive income (loss) (Note 19) | 1,008 | (40) | |
Retained earnings | 3,733 | 3,458 | |
Shareholders' equity | 21,030 | 19,288 | |
Non-controlling interests | 1,812 | 1,628 | |
Total equity | 22,842 | 20,916 | |
Total liabilities and equity | $ 64,252 | $ 57,659 | |
[1] (1) No par value. Unlimited authorized shares. 482.2 million and 474.8 million issued and outstanding as at December 31, 2022 and 2021, respectively |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - shares shares in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Common stock, shares issued (in shares) | 482.2 | 474.8 |
Common stock, shares outstanding (in shares) | 482.2 | 474.8 |
Consolidated Statements of Earn
Consolidated Statements of Earnings - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Income Statement [Abstract] | ||
Revenue (Note 5) | $ 11,043 | $ 9,448 |
Expenses | ||
Energy supply costs | 3,952 | 2,951 |
Operating expenses | 2,683 | 2,523 |
Depreciation and amortization | 1,668 | 1,505 |
Total expenses | 8,303 | 6,979 |
Operating income | 2,740 | 2,469 |
Other income, net (Note 21) | 165 | 173 |
Finance charges | 1,102 | 1,003 |
Earnings before income tax expense | 1,803 | 1,639 |
Income tax expense (Note 22) | 289 | 234 |
Net earnings | 1,514 | 1,405 |
Net earnings attributable to: | ||
Non-controlling interests | 120 | 111 |
Preference equity shareholders | 64 | 63 |
Common equity shareholders | 1,330 | 1,231 |
Net earnings | $ 1,514 | $ 1,405 |
Earnings per common share (Note 17) | ||
Basic (CAD per share) | $ 2.78 | $ 2.61 |
Diluted (CAD per share) | $ 2.78 | $ 2.61 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Comprehensive Income [Abstract] | ||
Net earnings | $ 1,514 | $ 1,405 |
Other comprehensive income ( loss) | ||
Unrealized foreign currency translation gains (losses), net of hedging activities and income tax recovery (expense) of $15 million and $(2) million, respectively | 1,100 | (93) |
Other, net of income tax expense of $21 million and $3 million, respectively | 73 | 8 |
Other comprehensive loss | 1,173 | (85) |
Comprehensive income | 2,687 | 1,320 |
Comprehensive income attributable to: | ||
Non-controlling interests | 245 | 100 |
Preference equity shareholders | 64 | 63 |
Common equity shareholders | 2,378 | 1,157 |
Comprehensive income | $ 2,687 | $ 1,320 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Comprehensive Income [Abstract] | ||
Unrealized foreign currency translation, tax recovery (expense) | $ 15 | $ (2) |
Other, income tax expense (recovery) | $ 21 | $ 3 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Operating activities | ||
Net earnings | $ 1,514 | $ 1,405 |
Adjustments to reconcile net earnings to net cash provided by operating activities: | ||
Depreciation - property, plant and equipment | 1,460 | 1,313 |
Amortization - intangible assets | 145 | 136 |
Amortization - other | 63 | 56 |
Deferred income tax expense (Note 22) | 182 | 147 |
Equity component, allowance for funds used during construction (Note 21) | (78) | (77) |
Other | 105 | 75 |
Change in long-term regulatory assets and liabilities | 162 | (4) |
Change in working capital (Note 24) | (479) | (144) |
Cash from operating activities | 3,074 | 2,907 |
Investing activities | ||
Additions to property, plant and equipment | (3,587) | (3,189) |
Additions to intangible assets | (278) | (197) |
Contributions in aid of construction | 111 | 93 |
Contributions to equity-accounted investees | (100) | 0 |
Other | (205) | (195) |
Cash used in investing activities | (4,059) | (3,488) |
Financing activities | ||
Proceeds from long-term debt, net of issuance costs (Note 14) | 3,067 | 1,324 |
Repayments of long-term debt and finance leases | (1,526) | (634) |
Borrowings under committed credit facilities | 6,651 | 5,082 |
Repayments under committed credit facilities | (6,381) | (4,749) |
Net change in short-term borrowings | (21) | 115 |
Issue of common shares, net of costs, and dividends reinvested | 53 | 60 |
Dividends | ||
Common shares, net of dividends reinvested | (673) | (608) |
Preference shares | (64) | (63) |
Subsidiary dividends paid to non-controlling interests | (66) | (58) |
Other | (5) | (18) |
Cash from financing activities | 1,035 | 451 |
Effect of exchange rate changes on cash and cash equivalents | 28 | 12 |
Change in cash and cash equivalents | 78 | (118) |
Cash and cash equivalents, beginning of year | 131 | 249 |
Cash and cash equivalents, end of year | $ 209 | $ 131 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) shares in Millions, $ in Millions | Total | Common Shares | Preference Shares (Note 18) | Additional Paid-In Capital | Accumulated Other Comprehensive Income (Loss) (Note 19) | Retained Earnings | Non-Controlling Interests |
Balance, beginning of period (shares) at Dec. 31, 2020 | 466.8 | ||||||
Balance, beginning of period at Dec. 31, 2020 | $ 20,284 | $ 13,819 | $ 1,623 | $ 11 | $ 34 | $ 3,210 | $ 1,587 |
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,405 | 1,294 | 111 | ||||
Other comprehensive income (loss) | (85) | (74) | (11) | ||||
Common shares issued (shares) | 8 | ||||||
Common shares issued | 416 | $ 418 | (2) | ||||
Subsidiary dividends paid to non-controlling interests | (58) | (58) | |||||
Dividends declared on common shares | (983) | (983) | |||||
Dividends on preference shares | (63) | (63) | |||||
Other | 0 | 1 | (1) | ||||
Balance, end of period (shares) at Dec. 31, 2021 | 474.8 | ||||||
Balance, end of period at Dec. 31, 2021 | 20,916 | $ 14,237 | 1,623 | 10 | (40) | 3,458 | 1,628 |
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,514 | 1,394 | 120 | ||||
Other comprehensive income (loss) | 1,173 | 1,048 | 125 | ||||
Common shares issued (shares) | 7.4 | ||||||
Common shares issued | 417 | $ 419 | (2) | ||||
Subsidiary dividends paid to non-controlling interests | (66) | (66) | |||||
Dividends declared on common shares | (1,055) | (1,055) | |||||
Dividends on preference shares | (64) | (64) | |||||
Other | 7 | 2 | 5 | ||||
Balance, end of period (shares) at Dec. 31, 2022 | 482.2 | ||||||
Balance, end of period at Dec. 31, 2022 | $ 22,842 | $ 14,656 | $ 1,623 | $ 10 | $ 1,008 | $ 3,733 | $ 1,812 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Stockholders' Equity [Abstract] | ||
Dividends declared on common shares (CAD per share) | $ 2.20 | $ 2.08 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2022 | |
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. ITC also has electric transmission system assets under construction in Wisconsin. 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 3,328 megawatts ("MW"), including 68 MW of solar capacity and 250 MW of wind 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 primarily includes 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 90 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 166 MW. FortisTCI consists of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a generating capacity of 86 MW, including 84 MW of diesel-powered generating capacity and 2 MW of solar capacity. 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 Fortis Belize Limited (formerly known as Belize Electric Company Limited). 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. 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 and non-regulated holding company expenses. |
Regulation
Regulation | 12 Months Ended |
Dec. 31, 2022 | |
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 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) (%) Regulated Utility Regulatory Authority 2022 2021 Significant Features ITC (2) Federal Energy Regulatory Commission ("FERC") 60.0 10.77 10.77 Cost-based formula rates, with annual true-up mechanism (3) Incentive adders TEP Arizona Corporation Commission ("ACC") (4) 53.0 9.15 9.15 COS regulation FERC (5) 9.79 9.79 Formula transmission rates UNS Electric ACC 52.8 9.50 9.50 UNS Gas ACC 50.8 9.75 9.75 Central Hudson (6) New York State Public Service Commission ("PSC") 49.0 9.00 9.00 COS regulation FortisBC Energy (7) British Columbia Utilities Commission ("BCUC") 38.5 8.75 8.75 COS regulation with formula components and incentives (8) FortisBC Electric (7) 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 8.52-9.30 COS regulation with incentive mechanisms Caribbean Utilities (11) Utility Regulation and Competition Office N/A 6.25-8.25 6.00-8.00 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. See "Significant Regulatory Developments" below (3) Annual true-up collected or refunded in rates within a two-year period (4) Approved ROE of 9.15% with a 0.20% return on the fair value increment. A general rate application requesting new rates effective September 1, 2023 is ongoing. See "Significant Regulatory Developments" below (5) The allowed common equity component for FERC transmission rates is formulaic, and is updated annually based on TEP's actual equity ratio (6) Effective July 1, 2021 Central Hudson's approved common equity component of capital structure was 50%, declining by 1% annually to 48% in the third rate year (7) A generic cost of capital ("GCOC") proceeding is ongoing. See "Significant Developments" below (8) Formula and incentives have been set through 2024 (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 expired as of December 31, 2022. See "Significant Regulatory Developments" below (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 Significant Regulatory Developments ITC ITC Midwest Capital Structure Complaint: In May 2022, the Iowa Coalition for Affordable Transmission ("ICAT") filed a complaint with FERC under Section 206 of the Federal Power Act requesting that ITC Midwest's common equity component of capital structure be reduced from 60% to 53%. ICAT alleged that ITC Midwest does not meet FERC's three-part test for authorizing the use of the utility's actual capital structure for rate-making purposes. In November 2022, FERC issued an order denying the complaint, and in December 2022, ICAT filed a request for rehearing with FERC. As at December 31, 2022, ITC Midwest has not recorded a regulatory liability related to the complaint. MISO Base ROE: In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating certain FERC orders that had established the methodology for setting the base ROE for transmission owners operating in the Midcontinent Independent System Operator, Inc. (“MISO”) region, including ITC. This matter dates back to complaints filed at FERC in 2013 and 2015 challenging the MISO base ROE then in effect. The court has remanded the matter to FERC for further process, the timing and outcome of which is unknown. Transmission Incentives: In 2021, FERC issued a supplemental notice of proposed rulemaking ("NOPR") on transmission incentives modifying the proposal in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point regional transmission organization ("RTO") ROE incentive adder for RTO members that have been members for longer than three years. The timing and outcome of this proceeding is unknown. UNS Energy TEP General Rate Application: In June 2022, TEP filed a general rate application with the ACC requesting new rates effective September 1, 2023 using a December 31, 2021 test year. The application reflects a US$136 million net increase in non-fuel and fuel-related revenue, as well as proposals to eliminate certain adjustor mechanisms, and modify an existing adjustor to provide more timely recovery of clean energy investments. The timing and outcome of this proceeding is unknown. Central Hudson Customer Information System ("CIS") Implementation: In December 2022, the PSC released a report into the deployment by Central Hudson of its new CIS. The PSC also issued an Order to Commence Proceeding and Show Cause, which directed Central Hudson to explain why the PSC should not pursue civil or administrative penalties or initiate a proceeding to review the prudence of the CIS implementation costs. Central Hudson was also required to submit a plan to eliminate bi-monthly bill estimates and to evaluate the customer impacts of such a change. Central Hudson's response was filed in January 2023. The timing and outcome of this proceeding is unknown. FortisBC Energy and FortisBC Electric GCOC Proceeding: In 2021, the BCUC initiated a proceeding including a review of the common equity component of capital structure and the allowed ROE. FortisBC filed a final argument with the BCUC in December 2022 and the proceeding remains ongoing, with a decision expected in the second quarter of 2023. FortisAlberta 2023/2024 GCOC Proceeding: In January 2022, the AUC initiated proceedings to establish the cost of capital parameters for Alberta regulated utilities for 2023 and to consider a formula-based approach to setting the allowed ROE for 2024 and beyond. In March 2022, the AUC issued a decision extending the existing allowed ROE of 8.5% using a 37% equity component of capital structure through 2023. The GCOC proceeding for 2024 and beyond remains ongoing, and a decision is expected in the third quarter of 2023. 2023 COS Application: In July 2022, the AUC issued a decision largely accepting the forecast requested in FortisAlberta's COS application. The associated compliance filing, including the updated 2023 revenue requirement, was approved by the AUC in December 2022. Third PBR Term : In July 2021, the AUC issued a decision confirming that Alberta distribution utilities will be subject to a third PBR term commencing in 2024 with going-in rates based on the 2023 COS rebasing. The AUC also initiated a new proceeding to consider the design of the third PBR term. FortisAlberta is participating in this proceeding and a decision from the AUC is expected in 2023. Rural Electrification Association ("REA") Cost Recovery : In 2021, the AUC determined that costs attributable to REAs, approximating $10 million annually, can no longer be recovered from FortisAlberta's rate payers , effective January 1, 2023. FortisAlberta filed an appeal with the Alberta Court of Appeal, asserting that the AUC erred in preventing the company from recovering these costs from its own rate payers to the extent that such costs cannot be recovered directly from REAs. The appeal was heard in December 2022, and a decision from the Court is expected in first quarter of 2023. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
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 ("U.S. 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. 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 U.S. 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 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 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 removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability (Note 8) against which actual removal costs are netted when incurred. 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 2022 totalled $45 million (2021 - $39 million) and is reported as a reduction of finance charges and the equity component is reported as other income (Note 21). Both components are recorded to earnings through depreciation expense over the estimated service lives of the applicable PPE. Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulators, 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 and ranged from 0.5% to 39.8% for 2022 (2021 - 0.9% to 39.8%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.7% for 2022 (2021 – 2.6%). The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows. 2022 2021 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 31 5-80 32 Gas 18-95 39 18-95 38 Transmission Electric 20-90 41 20-90 42 Gas 10-85 35 10-85 35 Generation 5-95 22 5-95 23 Other 3-80 11 3-70 13 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 2022 (2021 – 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. 2022 2021 (years) Service Life Weighted Service Life Weighted Computer software 3-15 5 3-15 4 Land, transmission and water rights 34-90 54 34-90 55 Other 10-100 11 10-100 11 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 total undiscounted cash flows expected to be generated by the asset may be below carrying value. 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 performed, 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 U.S. 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. In addition, 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 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 Alberta Electric System Operator. 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 probable. 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 Effective January 1, 2022, stock options have been excluded from the Corporation's long-term incentive mix. Compensation expense related to stock options granted in 2021 or prior were measured at the grant date using the Black-Scholes fair value option-pricing model with each grant amortized to compensation expense 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 and PSUs, represent cash-settled awards whereas RSU's represent cash or share-settled awards, depending on settlement elections and the 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, 2022 was $54.65 (2021 - $61.08). 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 U.S. 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, 2022 was US$1.00 =CA$1.36 (2021 – US$1.00=CA$1.26). Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which wa s US$1.00=CA$1.30 f or 2022 (2021 - US$1.00=CA$1.25). 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 U.S. 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. The Corporation's earnings from, and net investments in, foreign subsidiaries and certain equity-accounted investments are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through U.S. 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 value of derivatives is 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 Fortis Belize are not subject to income tax. Differences between the income tax expense or recovery recognized under U.S. 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). 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 $5.3 billion as at December 31, 2022 (2021 - $4.1 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. Use of Accounting Estimates The preparation of these consolidated financial statements in accordance with U.S. 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 Accounting Standards Updates ("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, 2022 | |
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 2022 or 2021. The lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy of $37 million in 2022 (2021 - $38 million) are inter-company transactions between non-regulated and regulated entities, which were not eliminated on consolidation. As at December 31, 2022, accounts receivable included $7 million due from Belize Electricity (2021 - $22 million). Regulated Non-Regulated Energy Inter- UNS Central FortisBC Fortis FortisBC Other Sub- Infra- Corporate segment ($ millions) ITC Energy Hudson Energy Alberta Electric Electric total structure and Other eliminations Total Year ended December 31, 2022 Revenue 1,906 2,758 1,325 2,084 680 487 1,652 10,892 151 — — 11,043 Energy supply costs — 1,213 525 1,055 — 141 1,013 3,947 5 — — 3,952 Operating expenses 481 691 571 364 166 133 217 2,623 40 20 — 2,683 Depreciation and amortization 385 365 104 298 243 67 187 1,649 17 2 — 1,668 Operating income 1,040 489 125 367 271 146 235 2,673 89 (22) — 2,740 Other income, net 48 22 59 22 5 6 14 176 1 (12) — 165 Finance charges 349 127 53 146 110 76 75 936 — 166 — 1,102 Income tax expense 184 56 28 39 15 12 22 356 18 (85) — 289 Net earnings 555 328 103 204 151 64 152 1,557 72 (115) — 1,514 Non-controlling interests 101 — — 1 — — 18 120 — — — 120 Preference share dividends — — — — — — — — — 64 — 64 Net earnings attributable to common equity shareholders 454 328 103 203 151 64 134 1,437 72 (179) — 1,330 Additions to property, plant and equipment and intangible assets 1,212 709 293 589 510 130 393 3,836 29 — — 3,865 As at December 31, 2022 Goodwill 8,318 1,873 612 913 228 235 258 12,437 27 — — 12,464 Total assets 23,478 12,678 5,131 8,875 5,547 2,596 4,916 63,221 884 159 (12) 64,252 Year ended December 31, 2021 Revenue 1,691 2,334 1,000 1,715 644 468 1,498 9,350 98 — — 9,448 Energy supply costs — 919 285 713 — 136 895 2,948 3 — — 2,951 Operating expenses 466 648 498 355 157 128 201 2,453 33 37 — 2,523 Depreciation and amortization 291 345 91 281 231 65 181 1,485 17 3 — 1,505 Operating income 934 422 126 366 256 139 221 2,464 45 (40) — 2,469 Other income, net 42 41 34 12 2 5 5 141 1 31 — 173 Finance charges 300 120 46 144 106 73 71 860 — 143 — 1,003 Income tax expense 156 51 21 48 11 12 21 320 8 (94) — 234 Net earnings 520 292 93 186 141 59 134 1,425 38 (58) — 1,405 Non-controlling interests 94 — — 1 — — 16 111 — — — 111 Preference share dividends — — — — — — — — — 63 — 63 Net earnings attributable to common equity shareholders 426 292 93 185 141 59 118 1,314 38 (121) — 1,231 Additions to property, plant and equipment and intangible assets 1,046 710 291 475 389 134 321 3,366 20 — — 3,386 As at December 31, 2021 Goodwill 7,755 1,746 570 913 228 235 246 11,693 27 — — 11,720 Total assets 21,020 11,126 4,356 8,135 5,201 2,540 4,357 56,735 777 295 (148) 57,659 |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | REVENUE ($ millions) 2022 2021 Electric and gas revenue United States ITC 1,911 1,694 UNS Energy 2,498 2,071 Central Hudson 1,307 962 Canada FortisBC Energy 2,080 1,645 FortisAlberta 655 622 FortisBC Electric 429 404 Newfoundland Power 722 701 Maritime Electric 234 223 FortisOntario 220 211 Caribbean Caribbean Utilities 349 248 FortisTCI 98 89 Total electric and gas revenue 10,503 8,870 Other services revenue (1) 409 382 Revenue from contracts with customers 10,912 9,252 Alternative revenue (28) (18) Other revenue 159 214 Total revenue 11,043 9,448 (1) Includes $266 million and $260 million from regulated operations for 2022 and 2021, respectively Revenue from Contracts with Customers Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue, all based on regulator-approved tariff rates 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. This mechanism is in place until the expiry of the current multi-year rate plan in 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, respectively, 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, as well as 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, 2022 | |
Receivables [Abstract] | |
Accounts Receivable and Other Current Assets | ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS ($ millions) 2022 2021 Trade accounts receivable 930 621 Unbilled accounts receivable 887 701 Allowance for credit losses (58) (53) 1,759 1,269 Other (1) 580 242 2,339 1,511 (1) 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 25) Allowance for Credit Losses The allowance for credit losses changed as follows. ($ millions) 2022 2021 Balance, beginning of year (53) (64) Credit loss expensed (27) (7) Credit loss deferral (6) — Write-offs, net of recoveries 30 18 Foreign exchange (2) — Balance, end of year (58) (53) See Note 25 for disclosure on the Corporation's credit risk. |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2022 | |
Inventory Disclosure [Abstract] | |
Inventories | INVENTORIES ($ millions) 2022 2021 Materials and supplies 394 318 Gas and fuel in storage 235 131 Coal inventory 32 29 661 478 |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | REGULATORY ASSETS AND LIABILITIES ($ millions ) 2022 2021 Regulatory assets Deferred income taxes (Note 3) 1,874 1,806 Rate stabilization and related accounts (1) 557 339 Deferred energy management costs (2) 445 384 Employee future benefits (Notes 3 and 23) 207 388 Deferred lease costs (3) 132 127 Manufactured gas plant site remediation deferral (Note 16) 97 96 Deferred restoration costs (4) 91 17 Derivatives (Notes 3 and 25) 84 20 Generation early retirement costs (5) 78 48 Other regulatory assets (6) 444 364 Total regulatory assets 4,009 3,589 Less: Current portion (914) (492) Long-term regulatory assets 3,095 3,097 ($ millions) 2022 2021 Regulatory liabilities Deferred income taxes (Note 3) 1,364 1,289 Future cost of removal (Note 3) 1,306 1,217 Employee future benefits (Notes 3 and 23) 306 196 Rate stabilization and related accounts (1) 297 116 Derivatives (Notes 3 and 25) 224 52 Renewable energy surcharge (7) 126 107 Energy efficiency liability (8) 89 83 Other regulatory liabilities (6) 203 162 Total regulatory liabilities 3,915 3,222 Less: Current portion (595) (357) Long-term regulatory liabilities 3,320 2,865 (1) 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). (2) 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 one (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) Deferred Restoration Costs: Incremental costs incurred at Central Hudson and Maritime Electric associated with restoration activities due to significant weather events . Incremental costs incurred in excess of that collected in customer rates at Central Hudson are recovered through rate stabilization accounts. The form and recovery period for Maritime Electric will be determined by the regulator. (5) Generation Early Retirement Costs: Includes costs at TEP associated with the retirement of the Navajo Generating Station ("Navajo") and Sundt Generating Facility Units 1 and 2 in 2019 and the San Juan Generating Station ("San Juan") in 2022, as approved for recovery by its regulator. (6) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million. (7) 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. (8) 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. Regulatory assets not earning a return: (i) totalled $1,980 million and $1,727 million as at December 31, 2022 and 2021, respectively; (ii) are primarily related to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related liabilities that, likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective regulators. |
Other Assets
Other Assets | 12 Months Ended |
Dec. 31, 2022 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | OTHER ASSETS ($ millions) 2022 2021 Employee future benefits (Note 23) 274 259 Equity investments (1) 201 92 Supplemental Executive Retirement Plan ("SERP") 155 165 RECs (Note 8) 142 112 Derivatives 118 40 Other investments 115 86 Operating leases (Note 15) 43 40 Deferred compensation plan 40 42 Other 125 119 1,213 955 (1) Includes investments in Belize Electricity and Wataynikaneyap Partnership 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 life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis (Note 25). |
Property, Plant And Equipment
Property, Plant And Equipment | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Property, Plant And Equipment | PROPERTY, PLANT AND EQUIPMENT ($ millions) Cost Accumulated Depreciation Net Book Value 2022 Distribution Electric 13,650 (3,715) 9,935 Gas 6,396 (1,626) 4,770 Transmission Electric 19,056 (4,074) 14,982 Gas 2,600 (800) 1,800 Generation 7,173 (2,679) 4,494 Other 4,803 (1,610) 3,193 Assets under construction 2,094 — 2,094 Land 395 — 395 56,167 (14,504) 41,663 2021 Distribution Electric 12,321 (3,359) 8,962 Gas 5,838 (1,504) 4,334 Transmission Electric 17,104 (3,610) 13,494 Gas 2,453 (756) 1,697 Generation 7,014 (2,691) 4,323 Other 4,362 (1,454) 2,908 Assets under construction 1,759 — 1,759 Land 339 — 339 51,190 (13,374) 37,816 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 assets associated with natural gas storage at Aitken Creek. As at December 31, 2022, assets under construction largely reflect ongoing transmission projects at ITC and UNS Energy. The cost of PPE under finance lease as at December 31, 2022 was $323 million (2021 - $323 million) and related accumulated depreciation was $117 million (2021 - $113 million) (Note 15). Jointly Owned Facilities UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2022, interests in jointly owned facilities consisted of the following. Ownership Accumulated Net Book ($ millions, except as indicated) (%) Cost Depreciation Value Transmission Facilities Various 1,333 (428) 905 Springerville Common Facilities 86.0 544 (294) 250 Springerville Coal Handling Facilities 83.0 281 (133) 148 Four Corners Units 4 and 5 ("Four Corners") 7.0 264 (119) 145 Gila River Common Facilities 50.0 118 (43) 75 Luna Energy Facility ("Luna") 33.3 77 — 77 2,617 (1,017) 1,600 |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | INTANGIBLE ASSETS Accumulated Net Book ($ millions ) Cost Amortization Value 2022 Computer software 985 (497) 488 Land, transmission and water rights 1,064 (171) 893 Other 135 (78) 57 Assets under construction 110 — 110 2,294 (746) 1,548 2021 Computer software 952 (518) 434 Land, transmission and water rights 941 (154) 787 Other 113 (69) 44 Assets under construction 78 — 78 2,084 (741) 1,343 Included in the cost of land, transmission and water rights as at December 31, 2022 was $117 million (2021 - $137 million) not subject to amortization. Amortization expense was $145 million for 2022 (2021 - $136 million). Amortization is estimated to average approximately $90 million for each of the next five years. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | GOODWILL ($ millions) 2022 2021 Balance, beginning of year 11,720 11,792 Foreign currency translation impacts (1) 744 (72) Balance, end of year 12,464 11,720 (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 U.S. dollar No goodwill impairment was recognized by the Corporation in 2022 or 2021. |
Accounts Payable and Other Curr
Accounts Payable and Other Current Liabilities | 12 Months Ended |
Dec. 31, 2022 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Other Current Liabilities | ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES ($ millions) 2022 2021 Trade accounts payable 886 774 Gas and fuel cost payable 512 269 Customer and other deposits 401 288 Accrued taxes other than income taxes 282 238 Dividends payable 278 259 Employee compensation and benefits payable 270 283 Interest payable 254 218 Derivatives (Note 25) 127 43 Income taxes payable 88 31 Employee future benefits (Note 23) 28 26 Manufactured gas plant site remediation (Note 16) 17 13 Other 145 128 3,288 2,570 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | LONG-TERM DEBT ($ millions ) Maturity Date 2022 2021 ITC Secured U.S. First Mortgage Bonds - 4.22% weighted average fixed rate (2021 - 4.31%) 2024-2055 3,344 2,736 Secured U.S. Senior Notes - 3.83% weighted average fixed rate (2021 - 3.90%) 2040-2055 1,186 1,011 Unsecured U.S. Senior Notes - 3.98% weighted average fixed rate (2021 - 3.61%) 2023-2043 4,541 4,108 Unsecured U.S. Shareholder Note - 6.00% fixed rate (2021 - 6.00%) 2028 270 252 UNS Energy Unsecured U.S. Tax-Exempt Bond - 4.00% weighted average fixed rate (2021 - 4.34%) 2029 123 359 Unsecured U.S. Fixed Rate Notes - 3.58% weighted average fixed rate (2021 - 3.62%) 2023-2052 3,450 2,780 Central Hudson Unsecured U.S. Promissory Notes - 4.14% weighted average fixed and variable rate (2021 - 3.83%) 2024-2060 1,526 1,177 FortisBC Energy Unsecured Debentures - 4.61% weighted average fixed rate (2021 - 4.61%) 2026-2052 3,295 3,145 FortisAlberta Unsecured Debentures - 4.49% weighted average fixed rate (2021 - 4.49%) 2024-2052 2,485 2,360 FortisBC Electric Secured Debentures - 8.80% fixed rate (2021 - 8.80%) 2023 25 25 Unsecured Debentures - 4.70% weighted average fixed rate (2021 - 4.77%) 2035-2052 860 760 Other Electric Secured First Mortgage Sinking Fund Bonds - 5.26% weighted average fixed rate (2021 - 5.61%) 2026-2060 666 627 Secured First Mortgage Bonds - 5.31% weighted average fixed rate (2021 - 5.31%) 2025-2061 260 260 Unsecured Senior Notes - 4.45% weighted average fixed rate (2021 - 4.45%) 2041-2048 152 152 Unsecured U.S. Senior Loan Notes and Bonds - 4.71% weighted average fixed and variable rate (2021 - 4.36%) 2023-2052 745 609 Corporate and Other Unsecured U.S. Senior Notes and Promissory Notes - 3.82% weighted average fixed rate (2021 - 3.82%) 2023-2044 2,691 2,509 Unsecured Debentures - 6.51% fixed rate (2021 - 6.51%) 2039 200 200 Unsecured Senior Notes - 3.31% weighted average fixed rate (2021 - 2.52%) 2028-2029 1,000 1,000 Long-term classification of credit facility borrowings 1,657 1,305 Fair value adjustment - ITC acquisition 102 107 Total long-term debt (Note 25) 28,578 25,482 Less: Deferred financing costs and debt discounts (166) (147) Less: Current installments of long-term debt (2,481) (1,628) 25,931 23,707 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 restricted payments, including special or extraordinary dividends, if immediately thereafter its consolidated debt to consolidated capitalization ratio would exceed 65%. Long-Term Debt Issuances in 2022 Month Issued Interest Rate (%) Maturity Amount ($ millions) Use of Proceeds ITC Secured first mortgage bonds January 2.93 2052 US 150 (1) (2) (3) (4) Secured senior notes May 3.05 2052 US 75 (1) (3) (4) Unsecured senior notes September 4.95 (5) 2027 US 600 (1) (4) (6) Secured first mortgage bonds October 3.87 2027 US 75 (2) Secured first mortgage bonds October 4.53 2052 US 75 (2) UNS Energy Unsecured senior notes February 3.25 2032 US 325 (4) (6) Central Hudson Unsecured senior notes January 2.37 2027 US 50 (4) (6) Unsecured senior notes January 2.59 2029 US 60 (4) (6) Unsecured senior notes September 5.07 2032 US 100 (1) (4) Unsecured senior notes September 5.42 2052 US 10 (1) (4) FortisBC Energy Unsecured debentures November 4.67 2052 150 (2) FortisAlberta Senior unsecured debentures May 4.62 2052 125 (1) FortisBC Electric Unsecured debentures March 4.16 2052 100 (1) Newfoundland Power First mortgage sinking fund bonds April 4.20 2052 75 (1) (4) (6) Caribbean Utilities Unsecured senior notes November 5.88 2052 US 80 (1) (3) Fortis Unsecured senior notes May 4.43 (7) 2029 500 (4) (8) (1) Repay short-term and/or credit facility borrowings (2) Fund or refinance, in part or in full, a portfolio of new and/or existing eligible green projects (3) Fund capital expenditures (4) General corporate purposes (5) ITC entered into interest rate swaps which reduced the effective interest rate to 3.54%. See Note 25 to the 2022 Annual Financial Statements (6) Repay maturing long-term debt (7) The Corporation entered into cross-currency interest rate swaps to effectively convert the debt into US$391 million with an interest rate of 4.34% (Note 25) (8) Fund the June 2022 redemption of the Corporation's $500 million, 2.85% senior unsecured notes due December 2023 Long-Term Debt Repayments The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows. ($ millions) Total 2023 2,481 2024 1,434 2025 518 2026 2,434 2027 1,977 Thereafter 19,734 28,578 In November 2022, 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, 2022, $2.0 billion remained available under the short-form base shelf prospectus. Credit Facilities ($ millions) Regulated Corporate 2022 2021 Total credit facilities 3,795 2,055 5,850 4,846 Credit facilities utilized: Short-term borrowings (1) (253) — (253) (247) Long-term debt (including current portion) (2) (922) (735) (1,657) (1,305) Letters of credit outstanding (76) (52) (128) (115) Credit facilities unutilized 2,544 1,268 3,812 3,179 (1) The weighted average interest rate was approximately 4.9% (2021 - 0.6%). (2) The weighted average interest rate was approximately 5.1% (2021 - 0.9%). The current portion was $1,376 million (2021 - $888 million). Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the Corporation's total revolving credit facilities. Approximately $5.6 billion of the total credit facilities are committed facilities with maturities ranging from 2023 through 2027 . In 2022, Central Hudson increased its available credit facilities from US$230 million to US$320 million. In May 2022, the Corporation amended its unsecured $1.3 billion revolving term committed credit facility agreement to extend the maturity to July 2027, and to establish a sustainability-linked loan structure based on the Corporation’s achievement of targets for diversity on the Board of Directors and Scope 1 greenhouse gas emissions for 2022 through 2025. Maximum potential annual margin pricing adjustments are +/- 5 basis points and +/- 1 basis point for drawn and undrawn funds, respectively. Also in May 2022, the Corporation entered into an unsecured US$500 million non-revolving term cr edit facility. The facility has an initial one-year term and is repayable at any time without penalty. Consolidated credit facilities of approximately $5.9 billion as at December 31, 2022 are itemized below. ($ millions) Amount Maturity Unsecured committed revolving credit facilities Regulated utilities ITC (1) US 900 2024 UNS Energy US 375 2026 Central Hudson US 250 2025 FortisBC Energy 700 2027 FortisAlberta 250 2027 FortisBC Electric 150 2027 Other Electric 255 (2) Other Electric US 83 2025 Corporate and Other 1,350 (3) Other facilities Regulated utilities Central Hudson - uncommitted credit facility US 70 n/a FortisBC Energy - uncommitted credit facility 55 2024 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 2023 Corporate and Other Unsecured non-revolving facility US 500 2023 Unsecured non-revolving facility 27 n/a (1) ITC also has a US$400 million commercial paper program, under which US$134 million was outstanding as at December 31, 2022 (2021 - US$155 million), as reported in short-term borrowings. (2) $65 million in 2025, $90 million in 2025 and $100 million in 2027 (3) $50 million in 2024 and $1.3 billion in 2027 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Leases | LEASES The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 25 years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises. The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 33 years. Leases were presented on the consolidated balance sheets as follows. ($ millions) 2022 2021 Operating leases Other assets 43 40 Accounts payable and other current liabilities (9) (8) Other liabilities (34) (32) Finance leases (1) Regulatory assets 132 127 PPE, net 206 210 Accounts payable and other current liabilities (2) (4) Finance leases (336) (333) (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. The components of lease expense were as follows . ($ millions) 2022 2021 Operating lease cost 9 8 Finance lease cost: Amortization 1 2 Interest 33 32 Variable lease cost 21 19 Total lease cost 64 61 As at December 31, 2022, the present value of minimum lease payments was as follows. ($ millions) Operating Finance Total 2023 10 35 45 2024 9 35 44 2025 6 35 41 2026 5 35 40 2027 3 36 39 Thereafter 19 1,001 1,020 52 1,177 1,229 Less: Imputed interest (9) (839) (848) Total lease obligations 43 338 381 Less: Current installments (9) (2) (11) 34 336 370 Supplemental lease information follows. ($ millions, except as indicated) 2022 2021 Weighted average remaining lease term (years) Operating leases 9 10 Finance leases 33 34 Weighted average discount rate (%) Operating leases 4.1 3.8 Finance leases 5.0 5.1 Cash payments related to lease liabilities Operating cash flows used for operating leases (8) (8) Financing cash flows used for finance leases (1) (2) |
Leases | LEASES The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 25 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 33 years. Leases were presented on the consolidated balance sheets as follows. ($ millions) 2022 2021 Operating leases Other assets 43 40 Accounts payable and other current liabilities (9) (8) Other liabilities (34) (32) Finance leases (1) Regulatory assets 132 127 PPE, net 206 210 Accounts payable and other current liabilities (2) (4) Finance leases (336) (333) (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. The components of lease expense were as follows . ($ millions) 2022 2021 Operating lease cost 9 8 Finance lease cost: Amortization 1 2 Interest 33 32 Variable lease cost 21 19 Total lease cost 64 61 As at December 31, 2022, the present value of minimum lease payments was as follows. ($ millions) Operating Finance Total 2023 10 35 45 2024 9 35 44 2025 6 35 41 2026 5 35 40 2027 3 36 39 Thereafter 19 1,001 1,020 52 1,177 1,229 Less: Imputed interest (9) (839) (848) Total lease obligations 43 338 381 Less: Current installments (9) (2) (11) 34 336 370 Supplemental lease information follows. ($ millions, except as indicated) 2022 2021 Weighted average remaining lease term (years) Operating leases 9 10 Finance leases 33 34 Weighted average discount rate (%) Operating leases 4.1 3.8 Finance leases 5.0 5.1 Cash payments related to lease liabilities Operating cash flows used for operating leases (8) (8) Financing cash flows used for finance leases (1) (2) |
Other Liabilities
Other Liabilities | 12 Months Ended |
Dec. 31, 2022 | |
Other Liabilities Disclosure [Abstract] | |
Other Liabilities | OTHER LIABILITIES ($ millions) 2022 2021 Employee future benefits (Note 23) 423 740 AROs (Note 3) 174 184 Customer and other deposits 107 99 Manufactured gas plant site remediation (1) 95 83 Stock-based compensation plans (Note 20) 79 96 Derivatives (Note 25) 72 7 Deferred compensation plan (Note 9) 48 50 Mine reclamation obligations (2) 39 44 Operating leases (Note 15) 34 32 Retail energy contract (3) 33 40 Other 42 34 1,146 1,409 (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, 2022, an obligation of $100 million was recognized, including a current portion of $5 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 $54 million. The present value of the estimated future liability is shown in the table above. (3) In 2020, FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment which is being amortized to revenue over the life of the agreement. |
Earnings Per Common Share
Earnings Per Common Share | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Earnings Per Common Share | EARNINGS PER COMMON SHARE Diluted earnings per share ("EPS") was calculated using the treasury stock method for stock options. 2022 2021 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares EPS Shareholders Shares EPS ($ millions) (# millions) ($) ($ millions) (# millions) ($) Basic EPS 1,330 478.6 2.78 1,231 470.9 2.61 Potential dilutive effect of stock options — 0.4 — — 0.5 — Diluted EPS 1,330 479.0 2.78 1,231 471.4 2.61 |
Preference Shares
Preference Shares | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Preference Shares | PREFERENCE SHARES Authorized An unlimited number of first preference shares and second preference shares, without nominal or par value. Issued and Outstanding 2022 2021 First Preference Shares Number Number of Shares Amount of Shares Amount (thousands) ($ millions) (thousands) ($ millions) Series F 5,000 122 5,000 122 Series G 9,200 225 9,200 225 Series H 7,665 188 7,665 188 Series I 2,335 57 2,335 57 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 Right to Initial Annual Dividend Redemption Redemption Convert on Yield Dividend Yield and/or 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 4.75 1.1875 — Currently Redeemable 25.00 — Fixed rate reset (3) (4) Series G 5.25 1.0983 2.13 September 1, 2023 25.00 — Series H 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 (4) (5) 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) 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 $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield. (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference shares of a specified series. (5) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income | ACCUMULATED OTHER COMPREHENSIVE INCOME ($ millions) Opening Balance Net Change Ending Balance 2022 Unrealized foreign currency translation gains (losses) Net investments in foreign operations 273 1,222 1,495 Hedges of net investments in foreign operations (276) (254) (530) Income tax (expense) recovery (8) 15 7 (11) 983 972 Other Interest rate hedges (Note 25) (5) 54 49 Unrealized employee future benefits (losses) gains (Note 23) (36) 30 (6) Income tax recovery (expense) 12 (19) (7) (29) 65 36 Accumulated other comprehensive income (40) 1,048 1,008 2021 Unrealized foreign currency translation gains (losses) Net investments in foreign operations 377 (104) 273 Hedges of net investments in foreign operations (299) 23 (276) Income tax expense (6) (2) (8) 72 (83) (11) Other Interest rate hedges (Note 25) (4) (1) (5) Unrealized employee future benefits (losses) gains (Note 23) (49) 13 (36) Income tax recovery (expense) 15 (3) 12 (38) 9 (29) Accumulated other comprehensive income 34 (74) (40) |
Stock-based Compensation Plans
Stock-based Compensation Plans | 12 Months Ended |
Dec. 31, 2022 | |
Share-Based Payment Arrangement [Abstract] | |
Stock-based Compensation Plans | STOCK-BASED COMPENSATION PLANS Stock Options Effective 2022, the Corporation no longer grants stock options. Existing options to purchase common shares of the Corporation 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. As at December 31, 2022, the Corporation had 2.3 million (2021 - 2.9 million) stock options outstanding with a weighted average exercise price of $47.72 (2021 - $47.20). The options vested as of December 31, 2022, were 1.5 million (2021 – 1.4 million) with a weighted average exercise price of $44.86 (2021 - $42.76). In 2022, 1 million stock options were exercised (2021 - 1 million) for cash proceeds of $26 million (2021 - $32 million) and an intrinsic value realized by employees of $9 million (2021 - $11 million). 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. 2022 2021 Number of units (thousands) Beginning of year 183 147 Granted 33 30 Notional dividends reinvested 8 6 End of year 224 183 The accrued liability has been recognized at the respective December 31 st VWAP (Note 3) and included in other liabilities (Note 16). The accrued liability, compensation expense and cash payout were not material for 2022 or 2021. 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 subsidiaries the Company's cumulative net income, as compared to the target established at the time of the grant. Beginning with the 2022 PSU grant, the Corporation's Scope 1 carbon reduction performance as compared to the target established at the time of the grant has been included in the payout percentage. The following table summarizes information related to PSUs. 2022 2021 Number of units (thousands) Beginning of year 1,898 1,976 Granted 580 587 Notional dividends reinvested 58 60 Paid out (712) (697) Cancelled/forfeited (34) (28) End of year 1,790 1,898 Additional information ($ millions) Compensation expense recognized 25 74 Compensation expense unrecognized (1) 24 33 Cash payout 66 50 Accrued liability as at December 31 (2) 90 132 Aggregate intrinsic value as at December 31 (3) 114 165 (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 31 st VWAP and included in accounts payable and other current liabilities and in 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. Effective January 1, 2020, new RSU issuances 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. 2022 2021 Number of units (thousands) Beginning of year 1,060 1,048 Granted 331 378 Notional dividends reinvested 29 32 Paid out (410) (371) Cancelled/forfeited (33) (27) End of year 977 1,060 Additional information ($ millions) Compensation expense recognized 16 26 Compensation expense unrecognized (1) 16 17 Cash payout 25 21 Accrued liability as at December 31 (2) 40 46 Aggregate intrinsic value as at December 31 (3) 56 63 (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 31 st 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
Other Income, Net | 12 Months Ended |
Dec. 31, 2022 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | OTHER INCOME, NET ($ millions) 2022 2021 Non-service component of net periodic benefit cost 92 45 Equity component of AFUDC 78 77 Interest income 11 5 (Loss) gain on derivatives, net (17) 30 (Loss) gain on retirement investments, net (18) 4 Other 19 12 165 173 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2022 | |
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. ($ millions) 2022 2021 Gross deferred income tax assets Regulatory liabilities 674 560 Tax loss and credit carryforwards 658 556 Employee future benefits 161 169 Other 160 91 1,653 1,376 Valuation allowance (32) (23) Net deferred income tax asset 1,621 1,353 Gross deferred income tax liabilities PPE (5,146) (4,571) Regulatory assets (388) (283) Intangible assets (147) (126) (5,681) (4,980) Net deferred income tax liability (4,060) (3,627) Income Tax Expense ($ millions) 2022 2021 Canadian Earnings before income tax expense 447 427 Current income tax 93 84 Deferred income tax (41) (35) Total Canadian 52 49 Foreign Earnings before income tax expense 1,356 1,212 Current income tax 14 3 Deferred income tax 223 182 Total Foreign 237 185 Income tax expense 289 234 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. ($ millions, except as indicated) 2022 2021 Earnings before income tax expense 1,803 1,639 Combined Canadian federal and provincial statutory income tax rate (%) 30.0 30.0 Expected federal and provincial taxes at statutory rate 541 492 Decrease resulting from: Foreign and other statutory rate differentials (162) (155) AFUDC (18) (16) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (74) (74) Items capitalized for accounting purposes but expensed for income tax purposes (7) (8) Other 9 (5) Income tax expense 289 234 Effective tax rate (%) 16.0 14.3 Income Tax Carryforwards ($ millions) Expiring Year 2022 Canadian Non-capital loss 2028-2042 393 Foreign Federal and state net operating loss (1) 2023-2042 3,093 Other tax credits 2023-2042 131 3,224 Total income tax carryforwards recognized 3,617 (1) Indefinite carryforward for Federal net operating losses, and for states that have adopted the Federal provisions, effective for tax years beginning after December 31, 2017 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, British Columbia and Alberta). The Corporation's 2018 to 2022 taxation years are still open for audit in Canadian jurisdictions, and its 2018 to 2022 taxation years are still open for audit in United States jurisdictions. |
Employee Future Benefits
Employee Future Benefits | 12 Months Ended |
Dec. 31, 2022 | |
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, 2019 for FortisBC Electric plans (non-unionized employees), Newfoundland Power, FortisAlberta and FortisOntario; December 31, 2020 for the Corporation; December 31, 2021 for FortisBC Energy and the remaining FortisBC Electric plans and December 31, 2022 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 2022 Target Allocation (weighted average %) 2022 2021 Equities 47 48 48 Fixed income 46 43 45 Real estate 6 8 6 Cash and other 1 1 1 100 100 100 Fair Value of Plan Assets ($ millions) Level 1 (1) Level 2 (1) Level 3 (1) Total 2022 Equities 666 1,005 — 1,671 Fixed income 199 1,289 — 1,488 Real estate — — 264 264 Private equities — — 18 18 Cash and other 5 22 — 27 870 2,316 282 3,468 2021 Equities 749 1,271 — 2,020 Fixed income 219 1,642 — 1,861 Real estate — — 235 235 Private equities — — 21 21 Cash and other 10 15 — 25 978 2,928 256 4,162 (1) See Note 25 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. ($ millions) 2022 2021 Balance, beginning of year 256 224 Return on plan assets 28 32 Foreign currency translation 3 — Purchases, sales and settlements (5) — Balance, end of year 282 256 Funded Status Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Change in benefit obligation (1) Balance, beginning of year 3,922 3,995 747 789 Service costs 106 109 35 35 Employee contributions 18 18 3 2 Interest costs 114 98 21 19 Benefits paid (195) (170) (29) (25) Actuarial gains (1,026) (111) (225) (70) Past service costs (credits)/plan amendments — (2) 1 — Foreign currency translation 124 (15) 29 (3) Balance, end of year (2) 3,063 3,922 582 747 Change in value of plan assets Balance, beginning of year 3,722 3,528 440 391 Actual return on plan assets (651) 291 (77) 48 Benefits paid (187) (158) (24) (21) Employee contributions 18 18 3 2 Employer contributions 54 55 19 22 Foreign currency translation 123 (12) 28 (2) Balance, end of year 3,079 3,722 389 440 Funded status 16 (200) (193) (307) Balance sheet presentation Other assets (Note 9) 188 204 86 55 Other current liabilities (Note 13) (15) (13) (13) (13) Other liabilities (Note 16) (157) (391) (266) (349) 16 (200) (193) (307) (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 $2,818 million as at December 31, 2022 (2021 - $3,586 million). For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2022, the obligation was $978 million compared to plan assets of $790 million (2021 - $2,188 million and $1,799 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, 2022, the obligation was $833 million compared to plan assets of $790 million (2021 - $1,243 million and $1,063 million, respectively). For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2022, the obligation was $310 million compared to plan assets of $31 million (2021 - $398 million and $36 million, respectively). Net Benefit Cost (1) Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Service costs 106 109 35 35 Interest costs 114 98 21 19 Expected return on plan assets (194) (177) (23) (19) Amortization of actuarial losses (gains) 4 36 (10) (2) Amortization of past service credits/plan amendments (1) (1) (1) (1) Regulatory adjustments (10) (1) 4 3 19 64 26 35 (1) The non-service benefit 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 ($ millions) 2022 2021 2022 2021 Unamortized net actuarial losses (gains) 9 33 (11) (5) Unamortized past service costs 1 1 7 7 Income tax (recovery) expense (2) (8) 1 — Accumulated other comprehensive income 8 26 (3) 2 Net actuarial losses (gains) 103 260 (195) (81) Past service credits (4) (5) (4) (6) Other regulatory deferrals (6) 10 7 14 93 265 (192) (73) Regulatory assets (Note 8) 207 376 — 12 Regulatory liabilities (Note 8) (114) (111) (192) (85) Net regulatory assets (liabilities) 93 265 (192) (73) The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory liabilities. Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Current year net actuarial gains (23) (10) (6) (4) Amortization of actuarial losses 1 1 — — Foreign currency translation (2) — — — Income tax expense 6 2 1 1 Total recognized in comprehensive income (18) (7) (5) (3) Current year net actuarial gains (155) (220) (118) (95) Past service cost/plan amendments — — 1 — Amortization of actuarial (losses) gains (6) (35) 10 2 Amortization of past service credits 1 2 1 2 Foreign currency translation 4 (2) (6) — Regulatory adjustments (16) (3) (7) (4) Total recognized in regulatory liabilities (172) (258) (119) (95) Significant Assumptions Defined Benefit OPEB Plans (weighted average %) 2022 2021 2022 2021 Discount rate during the year (1) 2.97 2.60 2.97 2.60 Discount rate as at December 31 5.27 3.00 5.36 2.97 Expected long-term rate of return on plan assets (2) 5.87 5.40 5.00 4.88 Rate of compensation increase 3.33 3.30 — — Health care cost trend increase as at December 31 (3) — — 4.48 4.49 (1) ITC and UNS Energy 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 2023 weighted average health care cost trend rate is 6.17% and is assumed to decrease over the next 12 years to the weighted average ultimate health care cost trend rate of 4.48% in 2034 and thereafter. Expected Benefit Payments Defined Benefit OPEB ($ millions) Pension Payments Payments 2023 $ 177 $ 30 2024 183 32 2025 190 33 2026 197 35 2027 203 35 2028-2032 1,094 191 During 2023, the Corporation expects to contribute $35 million for defined benefit pension plans and $20 million for OPEB plans. In 2022, the Corporation expensed $47 million (2021 - $44 million) related to defined contribution pension plans. |
Supplementary Cash Flow Informa
Supplementary Cash Flow Information | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Cash Flow Information | SUPPLEMENTARY CASH FLOW INFORMATION ($ millions) 2022 2021 Cash paid (received) for Interest 1,057 986 Income taxes 79 (13) Change in working capital Accounts receivable and other current assets (479) (88) Prepaid expenses (22) (15) Inventories (153) (56) Regulatory assets - current portion (307) (99) Accounts payable and other current liabilities 449 164 Regulatory liabilities - current portion 33 (50) (479) (144) Non-cash investing and financing activities Accrued capital expenditures 411 432 Common share dividends reinvested 364 356 Contributions in aid of construction 13 13 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments and Risk Management | 12 Months Ended |
Dec. 31, 2022 | |
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. Derivatives are recorded 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 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, 2022, unrealized losses of $84 million (2021 - $20 million) were recognized as regulatory assets and unrealized gains of $224 million (2021 - $52 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. In 2022, unrealized gains of $34 million (2021 - $21 million) were recognized in revenue. 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 o f $114 million and terms of one g at varying dates through January 2025. 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. In 2022, unrealized losses of $22 million (2021 - unrealized gains of $17 million) were recognized in other income, net. Foreign Exchange Contracts The Corporation holds U.S. dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through May 2024 and have a combined notional amount of $352 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. In 2022, unrealized losses of $9 million (2021 - $11 million) were recognized in other income, net. 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 US$450 million, were terminated in September 2022 with the issuance of US$600 million senior notes and realized gains of $52 million (US$39 million) were recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over five years. Cross-Currency Interest Rate Swaps In May 2022, the Corporation entered into cross-currency interest rate swaps with a 7-year term to effectively convert its $500 million, 4.43% unsecured senior notes to US$391 million, 4.34% debt (Note 14). The Corporation designated this notional U.S. debt as an effective hedge of its foreign net investments and unrealized gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income, consistent with the translation adjustment related to the net investments. Other changes in the fair value of the swaps are also recognized in other comprehensive income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash flow method based on secured overnight financing rates. In 2022, unrealized losses of $17 million were recorded in other comprehensive income. Other Investments UNS Energy holds investments in money market accounts, and ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees, which include mutual funds and money market accounts. These investments are recorded at fair value based on quoted market prices in active markets. Gains and losses are recognized in other income, net. In 2022, unrealized losses of $11 million (2021 - unrealized gains of $5 million) were recognized in other income, net. Recurring Fair Value Measures The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis. ($ millions) Level 1 (1) Level 2 (1) Level 3 (1) Total As at December 31, 2022 Assets Energy contracts subject to regulatory deferral (2) (3) — 304 — 304 Energy contracts not subject to regulatory deferral (2) — 49 — 49 Other investments (4) 150 — — 150 150 353 — 503 Liabilities Energy contracts subject to regulatory deferral (3) (5) — (164) — (164) Energy contracts not subject to regulatory deferral (5) — (8) — (8) Foreign exchange contracts, total return and cross-currency interest rate swaps (5) — (26) — (26) — (198) — (198) As at December 31, 2021 Assets Energy contracts subject to regulatory deferral (2) (3) — 78 — 78 Energy contracts not subject to regulatory deferral (2) — 16 — 16 Foreign exchange contracts, total return and interest rate swaps (2) 23 2 — 25 Other investments (4) 137 — — 137 160 96 — 256 Liabilities Energy contracts subject to regulatory deferral (3) (5) — (46) — (46) Energy contracts not subject to regulatory deferral (5) — (3) — (3) — (49) — (49) (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 cash and cash equivalents and other assets (5) Included in accounts payable and other current liabilities or other liabilities Energy Contracts 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. ($ millions) Gross Amount Counterparty Cash Collateral Net Amount As at December 31, 2022 Derivative assets 353 54 63 236 Derivative liabilities (172) (54) — (118) As at December 31, 2021 Derivative assets 94 25 7 62 Derivative liabilities (49) (25) — (24) Volume of Derivative Activity As at December 31, 2022, 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. 2022 2021 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 586 509 Electricity power purchase contracts (GWh) 224 731 Gas swap contracts (PJ) 185 151 Gas supply contract premiums (PJ) 148 144 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 1,886 1,886 Gas swap contracts (PJ) 34 29 (1) GWh means gigawatt hours and PJ means petajoules Credit Risk For cash equivalents, accounts receivable and other current assets, and long-term other receivables, credit risk is generally limited to the carrying value on the consolidated balance sheets. The Corporation's subsidiaries generally have a large and diversified customer base, which minimizes the concentration of credit risk. Policies in place to minimize credit risk include requiring customer deposits, prepayments and/or credit checks for certain customers, performing disconnections and/or using third-party collection agencies for overdue accounts. ITC has a concentration of credit risk as approxima tely 70% o f 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. Central Hudson has seen an increase in accounts receivable due to the suspension of collection efforts in response to the COVID-19 pandemic, as well as higher commodity prices. Central Hudson continues to proactively contact customers regarding past-due balances to advise them of financial assistance available through federal and state programs, and collection efforts are expected to expand in 2023. Under its regulatory framework, Central Hudson can defer uncollectible write-offs that exceed 10 basis points above the amounts collected in customer rates for future recovery. 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, Central Hudson and FortisBC Energy, 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 $178 million as at December 31, 2022 (2021 - $59 million). Hedge of Foreign Net Investments The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Fortis Belize Limited and Belize Electricity is, or is pegged to, the U.S. dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has limited this exposure through hedging. As at December 31, 2022, US$2.9 billion (2021 - US$2.2 billion) of corporately issued U.S. dollar-denominated long-term debt has been designated as an effective hedge of net investments, leaving approximately US$10.6 billion (2021 - US$10.8 billion) unhedged. Exchange rate fluctuations associated with the hedged net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive income. Financial Instruments Not Carried at Fair Value Excluding long-term debt, the consolidated carrying value of the Corporation's remaining financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES As at December 31, 2022, unconditional minimum purchase obligations were as follows. ($ millions) Total Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Gas and fuel purchase obligations (1) 5,720 1,024 516 461 374 328 3,017 Waneta Expansion capacity agreement (2) 2,472 54 55 56 58 59 2,190 Renewable PPAs (3) 1,926 131 131 131 131 130 1,272 Power purchase obligations (4) 1,691 334 253 191 192 113 608 ITC easement agreement (5) 380 14 14 14 14 14 310 Debt collection agreement (6) 106 3 3 3 3 3 91 Renewable energy credit purchase agreements (7) 77 18 14 7 7 6 25 Other (8) 132 21 9 20 3 3 76 12,504 1,599 995 883 782 656 7,589 (1) FortisBC Energy ($4,804 million): includes contracts of $2,720 million for the purchase of renewable natural gas expiring in 2044 and contracts of $2,084 million for the purchase of gas, renewable 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, 2022. The renewable gas supply obligations disclosed reflect the contracted price per GJ between the Corporation and the suppliers. UNS Energy ($801 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, the purchase of transmission services for purchased power, as well as natural gas commodity agreements based on projected market prices as of December 31, 2022. 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. (2) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion hydroelectric generating facility for forty-years, beginning April 2015. (3) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2051, 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. (4) Maritime Electric ($746 million): includes an energy purchase agreement and transmission capacity contract for 30 MW of capacity to PEI with New Brunswick Power, expiring December 2026 and November 2032, respectively. The agreements entitle Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and require Maritime Electric to pay its share of the station's capital operating costs for the life of the unit. FortisOntario ($489 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 ($258 million): includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning October 1, 2013. UNS Energy ($153 million): an agreement with Salt River Project Agricultural Improvement and Power District to purchase up to 300 MW of capacity, power and ancillary services through 2023. TEP will pay monthly capacity charges and variable power charges. (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 licenses 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, are collected in customer rates. (7) UNS Energy and Central Hudson are party to REC 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 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. The Wataynikaneyap Partnership has loan agreements in place 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 Four Corners and Luna, with agreements expiring in 2041 and 2046 respectively, and at San Juan and 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 San Juan and Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $339 million for Four Corners. As at December 31, 2022, 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 $74 million, for which it has issued a parental guarantee. As at December 31, 2022, there was no obligation under this guarantee. As at December 31, 2022, FortisBC Holdings Inc. ("FHI") had $142 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 2016, the Federal Court dismissed the Band's application for judicial review of the ministerial consent. In 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, 2022 | |
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 ("U.S. 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. 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 U.S. 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 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 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 removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability (Note 8) against which actual removal costs are netted when incurred. 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 2022 totalled $45 million (2021 - $39 million) and is reported as a reduction of finance charges and the equity component is reported as other income (Note 21). Both components are recorded to earnings through depreciation expense over the estimated service lives of the applicable PPE. Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulators, 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 and ranged from 0.5% to 39.8% for 2022 (2021 - 0.9% to 39.8%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.7% for 2022 (2021 – 2.6%). The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows. 2022 2021 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 31 5-80 32 Gas 18-95 39 18-95 38 Transmission Electric 20-90 41 20-90 42 Gas 10-85 35 10-85 35 Generation 5-95 22 5-95 23 Other 3-80 11 3-70 13 |
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 2022 (2021 – 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. 2022 2021 (years) Service Life Weighted Service Life Weighted Computer software 3-15 5 3-15 4 Land, transmission and water rights 34-90 54 34-90 55 Other 10-100 11 10-100 11 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 total undiscounted cash flows expected to be generated by the asset may be below carrying value. 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 performed, 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 U.S. 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. In addition, 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 | Leases A right-of-use asset and lease liability is recognized for 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 Alberta Electric System Operator. 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 probable. 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 Effective January 1, 2022, stock options have been excluded from the Corporation's long-term incentive mix. Compensation expense related to stock options granted in 2021 or prior were measured at the grant date using the Black-Scholes fair value option-pricing model with each grant amortized to compensation expense 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 and PSUs, represent cash-settled awards whereas RSU's represent cash or share-settled awards, depending on settlement elections and the 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, 2022 was $54.65 (2021 - $61.08). 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 U.S. 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, 2022 was US$1.00 =CA$1.36 (2021 – US$1.00=CA$1.26). Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which wa s US$1.00=CA$1.30 f or 2022 (2021 - US$1.00=CA$1.25). 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 . |
Derivatives 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 U.S. 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. The Corporation's earnings from, and net investments in, foreign subsidiaries and certain equity-accounted investments are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through U.S. 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. 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd) Derivatives and Hedging (cont'd) Presentation of Derivatives The fair value of derivatives is 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 Fortis Belize are not subject to income tax. Differences between the income tax expense or recovery recognized under U.S. 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). 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 $5.3 billion as at December 31, 2022 (2021 - $4.1 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. |
Use of Accounting Estimates | Use of Accounting Estimates The preparation of these consolidated financial statements in accordance with U.S. 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 | Future Accounting Pronouncements The Corporation considers the applicability and impact of all Accounting Standards Updates ("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. |
Regulation (Tables)
Regulation (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Schedule of Nature of Regulation | Nature of Regulation Allowed Common Equity (%) Allowed ROE (1) (%) Regulated Utility Regulatory Authority 2022 2021 Significant Features ITC (2) Federal Energy Regulatory Commission ("FERC") 60.0 10.77 10.77 Cost-based formula rates, with annual true-up mechanism (3) Incentive adders TEP Arizona Corporation Commission ("ACC") (4) 53.0 9.15 9.15 COS regulation FERC (5) 9.79 9.79 Formula transmission rates UNS Electric ACC 52.8 9.50 9.50 UNS Gas ACC 50.8 9.75 9.75 Central Hudson (6) New York State Public Service Commission ("PSC") 49.0 9.00 9.00 COS regulation FortisBC Energy (7) British Columbia Utilities Commission ("BCUC") 38.5 8.75 8.75 COS regulation with formula components and incentives (8) FortisBC Electric (7) 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 8.52-9.30 COS regulation with incentive mechanisms Caribbean Utilities (11) Utility Regulation and Competition Office N/A 6.25-8.25 6.00-8.00 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. See "Significant Regulatory Developments" below (3) Annual true-up collected or refunded in rates within a two-year period (4) Approved ROE of 9.15% with a 0.20% return on the fair value increment. A general rate application requesting new rates effective September 1, 2023 is ongoing. See "Significant Regulatory Developments" below (5) The allowed common equity component for FERC transmission rates is formulaic, and is updated annually based on TEP's actual equity ratio (6) Effective July 1, 2021 Central Hudson's approved common equity component of capital structure was 50%, declining by 1% annually to 48% in the third rate year (7) A generic cost of capital ("GCOC") proceeding is ongoing. See "Significant Developments" below (8) Formula and incentives have been set through 2024 (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 expired as of December 31, 2022. See "Significant Regulatory Developments" below (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, 2022 | |
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. 2022 2021 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 31 5-80 32 Gas 18-95 39 18-95 38 Transmission Electric 20-90 41 20-90 42 Gas 10-85 35 10-85 35 Generation 5-95 22 5-95 23 Other 3-80 11 3-70 13 ($ millions) Cost Accumulated Depreciation Net Book Value 2022 Distribution Electric 13,650 (3,715) 9,935 Gas 6,396 (1,626) 4,770 Transmission Electric 19,056 (4,074) 14,982 Gas 2,600 (800) 1,800 Generation 7,173 (2,679) 4,494 Other 4,803 (1,610) 3,193 Assets under construction 2,094 — 2,094 Land 395 — 395 56,167 (14,504) 41,663 2021 Distribution Electric 12,321 (3,359) 8,962 Gas 5,838 (1,504) 4,334 Transmission Electric 17,104 (3,610) 13,494 Gas 2,453 (756) 1,697 Generation 7,014 (2,691) 4,323 Other 4,362 (1,454) 2,908 Assets under construction 1,759 — 1,759 Land 339 — 339 51,190 (13,374) 37,816 |
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. 2022 2021 (years) Service Life Weighted Service Life Weighted Computer software 3-15 5 3-15 4 Land, transmission and water rights 34-90 54 34-90 55 Other 10-100 11 10-100 11 Accumulated Net Book ($ millions ) Cost Amortization Value 2022 Computer software 985 (497) 488 Land, transmission and water rights 1,064 (171) 893 Other 135 (78) 57 Assets under construction 110 — 110 2,294 (746) 1,548 2021 Computer software 952 (518) 434 Land, transmission and water rights 941 (154) 787 Other 113 (69) 44 Assets under construction 78 — 78 2,084 (741) 1,343 |
Segmented Information (Tables)
Segmented Information (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Schedule of Information by Reportable Segment | Regulated Non-Regulated Energy Inter- UNS Central FortisBC Fortis FortisBC Other Sub- Infra- Corporate segment ($ millions) ITC Energy Hudson Energy Alberta Electric Electric total structure and Other eliminations Total Year ended December 31, 2022 Revenue 1,906 2,758 1,325 2,084 680 487 1,652 10,892 151 — — 11,043 Energy supply costs — 1,213 525 1,055 — 141 1,013 3,947 5 — — 3,952 Operating expenses 481 691 571 364 166 133 217 2,623 40 20 — 2,683 Depreciation and amortization 385 365 104 298 243 67 187 1,649 17 2 — 1,668 Operating income 1,040 489 125 367 271 146 235 2,673 89 (22) — 2,740 Other income, net 48 22 59 22 5 6 14 176 1 (12) — 165 Finance charges 349 127 53 146 110 76 75 936 — 166 — 1,102 Income tax expense 184 56 28 39 15 12 22 356 18 (85) — 289 Net earnings 555 328 103 204 151 64 152 1,557 72 (115) — 1,514 Non-controlling interests 101 — — 1 — — 18 120 — — — 120 Preference share dividends — — — — — — — — — 64 — 64 Net earnings attributable to common equity shareholders 454 328 103 203 151 64 134 1,437 72 (179) — 1,330 Additions to property, plant and equipment and intangible assets 1,212 709 293 589 510 130 393 3,836 29 — — 3,865 As at December 31, 2022 Goodwill 8,318 1,873 612 913 228 235 258 12,437 27 — — 12,464 Total assets 23,478 12,678 5,131 8,875 5,547 2,596 4,916 63,221 884 159 (12) 64,252 Year ended December 31, 2021 Revenue 1,691 2,334 1,000 1,715 644 468 1,498 9,350 98 — — 9,448 Energy supply costs — 919 285 713 — 136 895 2,948 3 — — 2,951 Operating expenses 466 648 498 355 157 128 201 2,453 33 37 — 2,523 Depreciation and amortization 291 345 91 281 231 65 181 1,485 17 3 — 1,505 Operating income 934 422 126 366 256 139 221 2,464 45 (40) — 2,469 Other income, net 42 41 34 12 2 5 5 141 1 31 — 173 Finance charges 300 120 46 144 106 73 71 860 — 143 — 1,003 Income tax expense 156 51 21 48 11 12 21 320 8 (94) — 234 Net earnings 520 292 93 186 141 59 134 1,425 38 (58) — 1,405 Non-controlling interests 94 — — 1 — — 16 111 — — — 111 Preference share dividends — — — — — — — — — 63 — 63 Net earnings attributable to common equity shareholders 426 292 93 185 141 59 118 1,314 38 (121) — 1,231 Additions to property, plant and equipment and intangible assets 1,046 710 291 475 389 134 321 3,366 20 — — 3,386 As at December 31, 2021 Goodwill 7,755 1,746 570 913 228 235 246 11,693 27 — — 11,720 Total assets 21,020 11,126 4,356 8,135 5,201 2,540 4,357 56,735 777 295 (148) 57,659 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Revenue | ($ millions) 2022 2021 Electric and gas revenue United States ITC 1,911 1,694 UNS Energy 2,498 2,071 Central Hudson 1,307 962 Canada FortisBC Energy 2,080 1,645 FortisAlberta 655 622 FortisBC Electric 429 404 Newfoundland Power 722 701 Maritime Electric 234 223 FortisOntario 220 211 Caribbean Caribbean Utilities 349 248 FortisTCI 98 89 Total electric and gas revenue 10,503 8,870 Other services revenue (1) 409 382 Revenue from contracts with customers 10,912 9,252 Alternative revenue (28) (18) Other revenue 159 214 Total revenue 11,043 9,448 (1) Includes $266 million and $260 million from regulated operations for 2022 and 2021, respectively |
Accounts Receivable and Other_2
Accounts Receivable and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Receivables [Abstract] | |
Schedule Of Accounts Receivable and Other Current Assets | ($ millions) 2022 2021 Trade accounts receivable 930 621 Unbilled accounts receivable 887 701 Allowance for credit losses (58) (53) 1,759 1,269 Other (1) 580 242 2,339 1,511 (1) 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 25) |
Schedule of Allowance for Credit Losses | The allowance for credit losses changed as follows. ($ millions) 2022 2021 Balance, beginning of year (53) (64) Credit loss expensed (27) (7) Credit loss deferral (6) — Write-offs, net of recoveries 30 18 Foreign exchange (2) — Balance, end of year (58) (53) See Note 25 for disclosure on the Corporation's credit risk. |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Inventory Disclosure [Abstract] | |
Schedule of Utility Inventory | ($ millions) 2022 2021 Materials and supplies 394 318 Gas and fuel in storage 235 131 Coal inventory 32 29 661 478 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | ($ millions ) 2022 2021 Regulatory assets Deferred income taxes (Note 3) 1,874 1,806 Rate stabilization and related accounts (1) 557 339 Deferred energy management costs (2) 445 384 Employee future benefits (Notes 3 and 23) 207 388 Deferred lease costs (3) 132 127 Manufactured gas plant site remediation deferral (Note 16) 97 96 Deferred restoration costs (4) 91 17 Derivatives (Notes 3 and 25) 84 20 Generation early retirement costs (5) 78 48 Other regulatory assets (6) 444 364 Total regulatory assets 4,009 3,589 Less: Current portion (914) (492) Long-term regulatory assets 3,095 3,097 ($ millions) 2022 2021 Regulatory liabilities Deferred income taxes (Note 3) 1,364 1,289 Future cost of removal (Note 3) 1,306 1,217 Employee future benefits (Notes 3 and 23) 306 196 Rate stabilization and related accounts (1) 297 116 Derivatives (Notes 3 and 25) 224 52 Renewable energy surcharge (7) 126 107 Energy efficiency liability (8) 89 83 Other regulatory liabilities (6) 203 162 Total regulatory liabilities 3,915 3,222 Less: Current portion (595) (357) Long-term regulatory liabilities 3,320 2,865 (1) 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). (2) 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 one (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) Deferred Restoration Costs: Incremental costs incurred at Central Hudson and Maritime Electric associated with restoration activities due to significant weather events . Incremental costs incurred in excess of that collected in customer rates at Central Hudson are recovered through rate stabilization accounts. The form and recovery period for Maritime Electric will be determined by the regulator. (5) Generation Early Retirement Costs: Includes costs at TEP associated with the retirement of the Navajo Generating Station ("Navajo") and Sundt Generating Facility Units 1 and 2 in 2019 and the San Juan Generating Station ("San Juan") in 2022, as approved for recovery by its regulator. (6) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million. (7) Renewable Energy Surcharge: Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset. The ACC measures RES compliance through Renewable Energy Credits ("RECs"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount. (8) Energy Efficiency Liability: The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator. |
Schedule of Regulatory Liabilities | ($ millions ) 2022 2021 Regulatory assets Deferred income taxes (Note 3) 1,874 1,806 Rate stabilization and related accounts (1) 557 339 Deferred energy management costs (2) 445 384 Employee future benefits (Notes 3 and 23) 207 388 Deferred lease costs (3) 132 127 Manufactured gas plant site remediation deferral (Note 16) 97 96 Deferred restoration costs (4) 91 17 Derivatives (Notes 3 and 25) 84 20 Generation early retirement costs (5) 78 48 Other regulatory assets (6) 444 364 Total regulatory assets 4,009 3,589 Less: Current portion (914) (492) Long-term regulatory assets 3,095 3,097 ($ millions) 2022 2021 Regulatory liabilities Deferred income taxes (Note 3) 1,364 1,289 Future cost of removal (Note 3) 1,306 1,217 Employee future benefits (Notes 3 and 23) 306 196 Rate stabilization and related accounts (1) 297 116 Derivatives (Notes 3 and 25) 224 52 Renewable energy surcharge (7) 126 107 Energy efficiency liability (8) 89 83 Other regulatory liabilities (6) 203 162 Total regulatory liabilities 3,915 3,222 Less: Current portion (595) (357) Long-term regulatory liabilities 3,320 2,865 (1) 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). (2) 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 one (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) Deferred Restoration Costs: Incremental costs incurred at Central Hudson and Maritime Electric associated with restoration activities due to significant weather events . Incremental costs incurred in excess of that collected in customer rates at Central Hudson are recovered through rate stabilization accounts. The form and recovery period for Maritime Electric will be determined by the regulator. (5) Generation Early Retirement Costs: Includes costs at TEP associated with the retirement of the Navajo Generating Station ("Navajo") and Sundt Generating Facility Units 1 and 2 in 2019 and the San Juan Generating Station ("San Juan") in 2022, as approved for recovery by its regulator. (6) Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million. (7) Renewable Energy Surcharge: Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset. The ACC measures RES compliance through Renewable Energy Credits ("RECs"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount. (8) Energy Efficiency Liability: The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator. |
Other Assets (Tables)
Other Assets (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of Other Assets | ($ millions) 2022 2021 Employee future benefits (Note 23) 274 259 Equity investments (1) 201 92 Supplemental Executive Retirement Plan ("SERP") 155 165 RECs (Note 8) 142 112 Derivatives 118 40 Other investments 115 86 Operating leases (Note 15) 43 40 Deferred compensation plan 40 42 Other 125 119 1,213 955 (1) Includes investments in Belize Electricity and Wataynikaneyap Partnership |
Property, Plant And Equipment (
Property, Plant And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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. 2022 2021 (years) Service Life Ranges Weighted Service Life Weighted Distribution Electric 5-80 31 5-80 32 Gas 18-95 39 18-95 38 Transmission Electric 20-90 41 20-90 42 Gas 10-85 35 10-85 35 Generation 5-95 22 5-95 23 Other 3-80 11 3-70 13 ($ millions) Cost Accumulated Depreciation Net Book Value 2022 Distribution Electric 13,650 (3,715) 9,935 Gas 6,396 (1,626) 4,770 Transmission Electric 19,056 (4,074) 14,982 Gas 2,600 (800) 1,800 Generation 7,173 (2,679) 4,494 Other 4,803 (1,610) 3,193 Assets under construction 2,094 — 2,094 Land 395 — 395 56,167 (14,504) 41,663 2021 Distribution Electric 12,321 (3,359) 8,962 Gas 5,838 (1,504) 4,334 Transmission Electric 17,104 (3,610) 13,494 Gas 2,453 (756) 1,697 Generation 7,014 (2,691) 4,323 Other 4,362 (1,454) 2,908 Assets under construction 1,759 — 1,759 Land 339 — 339 51,190 (13,374) 37,816 |
Schedule of Jointly-Owned Facilities | As at December 31, 2022, interests in jointly owned facilities consisted of the following. Ownership Accumulated Net Book ($ millions, except as indicated) (%) Cost Depreciation Value Transmission Facilities Various 1,333 (428) 905 Springerville Common Facilities 86.0 544 (294) 250 Springerville Coal Handling Facilities 83.0 281 (133) 148 Four Corners Units 4 and 5 ("Four Corners") 7.0 264 (119) 145 Gila River Common Facilities 50.0 118 (43) 75 Luna Energy Facility ("Luna") 33.3 77 — 77 2,617 (1,017) 1,600 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Indefinite-Lived Intangible Assets | Accumulated Net Book ($ millions ) Cost Amortization Value 2022 Computer software 985 (497) 488 Land, transmission and water rights 1,064 (171) 893 Other 135 (78) 57 Assets under construction 110 — 110 2,294 (746) 1,548 2021 Computer software 952 (518) 434 Land, transmission and water rights 941 (154) 787 Other 113 (69) 44 Assets under construction 78 — 78 2,084 (741) 1,343 |
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. 2022 2021 (years) Service Life Weighted Service Life Weighted Computer software 3-15 5 3-15 4 Land, transmission and water rights 34-90 54 34-90 55 Other 10-100 11 10-100 11 Accumulated Net Book ($ millions ) Cost Amortization Value 2022 Computer software 985 (497) 488 Land, transmission and water rights 1,064 (171) 893 Other 135 (78) 57 Assets under construction 110 — 110 2,294 (746) 1,548 2021 Computer software 952 (518) 434 Land, transmission and water rights 941 (154) 787 Other 113 (69) 44 Assets under construction 78 — 78 2,084 (741) 1,343 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | ($ millions) 2022 2021 Balance, beginning of year 11,720 11,792 Foreign currency translation impacts (1) 744 (72) Balance, end of year 12,464 11,720 (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 U.S. dollar |
Accounts Payable and Other Cu_2
Accounts Payable and Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other Current Liabilities | ($ millions) 2022 2021 Trade accounts payable 886 774 Gas and fuel cost payable 512 269 Customer and other deposits 401 288 Accrued taxes other than income taxes 282 238 Dividends payable 278 259 Employee compensation and benefits payable 270 283 Interest payable 254 218 Derivatives (Note 25) 127 43 Income taxes payable 88 31 Employee future benefits (Note 23) 28 26 Manufactured gas plant site remediation (Note 16) 17 13 Other 145 128 3,288 2,570 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | ($ millions ) Maturity Date 2022 2021 ITC Secured U.S. First Mortgage Bonds - 4.22% weighted average fixed rate (2021 - 4.31%) 2024-2055 3,344 2,736 Secured U.S. Senior Notes - 3.83% weighted average fixed rate (2021 - 3.90%) 2040-2055 1,186 1,011 Unsecured U.S. Senior Notes - 3.98% weighted average fixed rate (2021 - 3.61%) 2023-2043 4,541 4,108 Unsecured U.S. Shareholder Note - 6.00% fixed rate (2021 - 6.00%) 2028 270 252 UNS Energy Unsecured U.S. Tax-Exempt Bond - 4.00% weighted average fixed rate (2021 - 4.34%) 2029 123 359 Unsecured U.S. Fixed Rate Notes - 3.58% weighted average fixed rate (2021 - 3.62%) 2023-2052 3,450 2,780 Central Hudson Unsecured U.S. Promissory Notes - 4.14% weighted average fixed and variable rate (2021 - 3.83%) 2024-2060 1,526 1,177 FortisBC Energy Unsecured Debentures - 4.61% weighted average fixed rate (2021 - 4.61%) 2026-2052 3,295 3,145 FortisAlberta Unsecured Debentures - 4.49% weighted average fixed rate (2021 - 4.49%) 2024-2052 2,485 2,360 FortisBC Electric Secured Debentures - 8.80% fixed rate (2021 - 8.80%) 2023 25 25 Unsecured Debentures - 4.70% weighted average fixed rate (2021 - 4.77%) 2035-2052 860 760 Other Electric Secured First Mortgage Sinking Fund Bonds - 5.26% weighted average fixed rate (2021 - 5.61%) 2026-2060 666 627 Secured First Mortgage Bonds - 5.31% weighted average fixed rate (2021 - 5.31%) 2025-2061 260 260 Unsecured Senior Notes - 4.45% weighted average fixed rate (2021 - 4.45%) 2041-2048 152 152 Unsecured U.S. Senior Loan Notes and Bonds - 4.71% weighted average fixed and variable rate (2021 - 4.36%) 2023-2052 745 609 Corporate and Other Unsecured U.S. Senior Notes and Promissory Notes - 3.82% weighted average fixed rate (2021 - 3.82%) 2023-2044 2,691 2,509 Unsecured Debentures - 6.51% fixed rate (2021 - 6.51%) 2039 200 200 Unsecured Senior Notes - 3.31% weighted average fixed rate (2021 - 2.52%) 2028-2029 1,000 1,000 Long-term classification of credit facility borrowings 1,657 1,305 Fair value adjustment - ITC acquisition 102 107 Total long-term debt (Note 25) 28,578 25,482 Less: Deferred financing costs and debt discounts (166) (147) Less: Current installments of long-term debt (2,481) (1,628) 25,931 23,707 Long-Term Debt Issuances in 2022 Month Issued Interest Rate (%) Maturity Amount ($ millions) Use of Proceeds ITC Secured first mortgage bonds January 2.93 2052 US 150 (1) (2) (3) (4) Secured senior notes May 3.05 2052 US 75 (1) (3) (4) Unsecured senior notes September 4.95 (5) 2027 US 600 (1) (4) (6) Secured first mortgage bonds October 3.87 2027 US 75 (2) Secured first mortgage bonds October 4.53 2052 US 75 (2) UNS Energy Unsecured senior notes February 3.25 2032 US 325 (4) (6) Central Hudson Unsecured senior notes January 2.37 2027 US 50 (4) (6) Unsecured senior notes January 2.59 2029 US 60 (4) (6) Unsecured senior notes September 5.07 2032 US 100 (1) (4) Unsecured senior notes September 5.42 2052 US 10 (1) (4) FortisBC Energy Unsecured debentures November 4.67 2052 150 (2) FortisAlberta Senior unsecured debentures May 4.62 2052 125 (1) FortisBC Electric Unsecured debentures March 4.16 2052 100 (1) Newfoundland Power First mortgage sinking fund bonds April 4.20 2052 75 (1) (4) (6) Caribbean Utilities Unsecured senior notes November 5.88 2052 US 80 (1) (3) Fortis Unsecured senior notes May 4.43 (7) 2029 500 (4) (8) (1) Repay short-term and/or credit facility borrowings (2) Fund or refinance, in part or in full, a portfolio of new and/or existing eligible green projects (3) Fund capital expenditures (4) General corporate purposes (5) ITC entered into interest rate swaps which reduced the effective interest rate to 3.54%. See Note 25 to the 2022 Annual Financial Statements (6) Repay maturing long-term debt (7) The Corporation entered into cross-currency interest rate swaps to effectively convert the debt into US$391 million with an interest rate of 4.34% (Note 25) (8) Fund the June 2022 redemption of the Corporation's $500 million, 2.85% senior unsecured notes due December 2023 |
Schedule of Long-Term Debt Repayments | The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows. ($ millions) Total 2023 2,481 2024 1,434 2025 518 2026 2,434 2027 1,977 Thereafter 19,734 28,578 |
Schedule of Credit Facilities | ($ millions) Regulated Corporate 2022 2021 Total credit facilities 3,795 2,055 5,850 4,846 Credit facilities utilized: Short-term borrowings (1) (253) — (253) (247) Long-term debt (including current portion) (2) (922) (735) (1,657) (1,305) Letters of credit outstanding (76) (52) (128) (115) Credit facilities unutilized 2,544 1,268 3,812 3,179 (1) The weighted average interest rate was approximately 4.9% (2021 - 0.6%). (2) The weighted average interest rate was approximately 5.1% (2021 - 0.9%). The current portion was $1,376 million (2021 - $888 million). Consolidated credit facilities of approximately $5.9 billion as at December 31, 2022 are itemized below. ($ millions) Amount Maturity Unsecured committed revolving credit facilities Regulated utilities ITC (1) US 900 2024 UNS Energy US 375 2026 Central Hudson US 250 2025 FortisBC Energy 700 2027 FortisAlberta 250 2027 FortisBC Electric 150 2027 Other Electric 255 (2) Other Electric US 83 2025 Corporate and Other 1,350 (3) Other facilities Regulated utilities Central Hudson - uncommitted credit facility US 70 n/a FortisBC Energy - uncommitted credit facility 55 2024 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 2023 Corporate and Other Unsecured non-revolving facility US 500 2023 Unsecured non-revolving facility 27 n/a (1) ITC also has a US$400 million commercial paper program, under which US$134 million was outstanding as at December 31, 2022 (2021 - US$155 million), as reported in short-term borrowings. (2) $65 million in 2025, $90 million in 2025 and $100 million in 2027 (3) $50 million in 2024 and $1.3 billion in 2027 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Schedule of Operating and Finance Leases Balance Sheet Location | Leases were presented on the consolidated balance sheets as follows. ($ millions) 2022 2021 Operating leases Other assets 43 40 Accounts payable and other current liabilities (9) (8) Other liabilities (34) (32) Finance leases (1) Regulatory assets 132 127 PPE, net 206 210 Accounts payable and other current liabilities (2) (4) Finance leases (336) (333) (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. The components of lease expense were as follows . |
Components of Lease Expense and Supplemental Lease Information | ($ millions) 2022 2021 Operating lease cost 9 8 Finance lease cost: Amortization 1 2 Interest 33 32 Variable lease cost 21 19 Total lease cost 64 61 Supplemental lease information follows. ($ millions, except as indicated) 2022 2021 Weighted average remaining lease term (years) Operating leases 9 10 Finance leases 33 34 Weighted average discount rate (%) Operating leases 4.1 3.8 Finance leases 5.0 5.1 Cash payments related to lease liabilities Operating cash flows used for operating leases (8) (8) Financing cash flows used for finance leases (1) (2) |
Present Value of Minimum Finance Lease Payments | As at December 31, 2022, the present value of minimum lease payments was as follows. ($ millions) Operating Finance Total 2023 10 35 45 2024 9 35 44 2025 6 35 41 2026 5 35 40 2027 3 36 39 Thereafter 19 1,001 1,020 52 1,177 1,229 Less: Imputed interest (9) (839) (848) Total lease obligations 43 338 381 Less: Current installments (9) (2) (11) 34 336 370 |
Present Value of Minimum Operating Lease Payments | As at December 31, 2022, the present value of minimum lease payments was as follows. ($ millions) Operating Finance Total 2023 10 35 45 2024 9 35 44 2025 6 35 41 2026 5 35 40 2027 3 36 39 Thereafter 19 1,001 1,020 52 1,177 1,229 Less: Imputed interest (9) (839) (848) Total lease obligations 43 338 381 Less: Current installments (9) (2) (11) 34 336 370 |
Other Liabilities (Tables)
Other Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Other Liabilities Disclosure [Abstract] | |
Schedule of Other Liabilities | ($ millions) 2022 2021 Employee future benefits (Note 23) 423 740 AROs (Note 3) 174 184 Customer and other deposits 107 99 Manufactured gas plant site remediation (1) 95 83 Stock-based compensation plans (Note 20) 79 96 Derivatives (Note 25) 72 7 Deferred compensation plan (Note 9) 48 50 Mine reclamation obligations (2) 39 44 Operating leases (Note 15) 34 32 Retail energy contract (3) 33 40 Other 42 34 1,146 1,409 (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, 2022, an obligation of $100 million was recognized, including a current portion of $5 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 $54 million. The present value of the estimated future liability is shown in the table above. (3) In 2020, FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment which is being amortized to revenue over the life of the agreement. |
Earnings Per Common Share (Tabl
Earnings Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings per Common Share | Diluted earnings per share ("EPS") was calculated using the treasury stock method for stock options. 2022 2021 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares EPS Shareholders Shares EPS ($ millions) (# millions) ($) ($ millions) (# millions) ($) Basic EPS 1,330 478.6 2.78 1,231 470.9 2.61 Potential dilutive effect of stock options — 0.4 — — 0.5 — Diluted EPS 1,330 479.0 2.78 1,231 471.4 2.61 |
Preference Shares (Tables)
Preference Shares (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Preference Shares Issued and Outstanding | Issued and Outstanding 2022 2021 First Preference Shares Number Number of Shares Amount of Shares Amount (thousands) ($ millions) (thousands) ($ millions) Series F 5,000 122 5,000 122 Series G 9,200 225 9,200 225 Series H 7,665 188 7,665 188 Series I 2,335 57 2,335 57 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 Right to Initial Annual Dividend Redemption Redemption Convert on Yield Dividend Yield and/or 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 4.75 1.1875 — Currently Redeemable 25.00 — Fixed rate reset (3) (4) Series G 5.25 1.0983 2.13 September 1, 2023 25.00 — Series H 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 (4) (5) 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) 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 $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield. (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference shares of a specified series. (5) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield. |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Change in Accumulated Other Comprehensive Income by Category | ($ millions) Opening Balance Net Change Ending Balance 2022 Unrealized foreign currency translation gains (losses) Net investments in foreign operations 273 1,222 1,495 Hedges of net investments in foreign operations (276) (254) (530) Income tax (expense) recovery (8) 15 7 (11) 983 972 Other Interest rate hedges (Note 25) (5) 54 49 Unrealized employee future benefits (losses) gains (Note 23) (36) 30 (6) Income tax recovery (expense) 12 (19) (7) (29) 65 36 Accumulated other comprehensive income (40) 1,048 1,008 2021 Unrealized foreign currency translation gains (losses) Net investments in foreign operations 377 (104) 273 Hedges of net investments in foreign operations (299) 23 (276) Income tax expense (6) (2) (8) 72 (83) (11) Other Interest rate hedges (Note 25) (4) (1) (5) Unrealized employee future benefits (losses) gains (Note 23) (49) 13 (36) Income tax recovery (expense) 15 (3) 12 (38) 9 (29) Accumulated other comprehensive income 34 (74) (40) |
Stock-based Compensation Plans
Stock-based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Share-Based Payment Arrangement [Abstract] | |
DSU Plan Activity | The following table summarizes information related to DSUs. 2022 2021 Number of units (thousands) Beginning of year 183 147 Granted 33 30 Notional dividends reinvested 8 6 End of year 224 183 |
PSU Plans Activity | The following table summarizes information related to PSUs. 2022 2021 Number of units (thousands) Beginning of year 1,898 1,976 Granted 580 587 Notional dividends reinvested 58 60 Paid out (712) (697) Cancelled/forfeited (34) (28) End of year 1,790 1,898 Additional information ($ millions) Compensation expense recognized 25 74 Compensation expense unrecognized (1) 24 33 Cash payout 66 50 Accrued liability as at December 31 (2) 90 132 Aggregate intrinsic value as at December 31 (3) 114 165 (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 31 st VWAP and included in accounts payable and other current liabilities and in 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. 2022 2021 Number of units (thousands) Beginning of year 1,060 1,048 Granted 331 378 Notional dividends reinvested 29 32 Paid out (410) (371) Cancelled/forfeited (33) (27) End of year 977 1,060 Additional information ($ millions) Compensation expense recognized 16 26 Compensation expense unrecognized (1) 16 17 Cash payout 25 21 Accrued liability as at December 31 (2) 40 46 Aggregate intrinsic value as at December 31 (3) 56 63 (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 31 st 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, 2022 | |
Other Income and Expenses [Abstract] | |
Schedule of Other Income, Net | ($ millions) 2022 2021 Non-service component of net periodic benefit cost 92 45 Equity component of AFUDC 78 77 Interest income 11 5 (Loss) gain on derivatives, net (17) 30 (Loss) gain on retirement investments, net (18) 4 Other 19 12 165 173 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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. ($ millions) 2022 2021 Gross deferred income tax assets Regulatory liabilities 674 560 Tax loss and credit carryforwards 658 556 Employee future benefits 161 169 Other 160 91 1,653 1,376 Valuation allowance (32) (23) Net deferred income tax asset 1,621 1,353 Gross deferred income tax liabilities PPE (5,146) (4,571) Regulatory assets (388) (283) Intangible assets (147) (126) (5,681) (4,980) Net deferred income tax liability (4,060) (3,627) |
Schedule of Components of Income Tax Expense | Income Tax Expense ($ millions) 2022 2021 Canadian Earnings before income tax expense 447 427 Current income tax 93 84 Deferred income tax (41) (35) Total Canadian 52 49 Foreign Earnings before income tax expense 1,356 1,212 Current income tax 14 3 Deferred income tax 223 182 Total Foreign 237 185 Income tax expense 289 234 |
Schedule of Effective Income Tax Rate Reconciliation | The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes. ($ millions, except as indicated) 2022 2021 Earnings before income tax expense 1,803 1,639 Combined Canadian federal and provincial statutory income tax rate (%) 30.0 30.0 Expected federal and provincial taxes at statutory rate 541 492 Decrease resulting from: Foreign and other statutory rate differentials (162) (155) AFUDC (18) (16) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (74) (74) Items capitalized for accounting purposes but expensed for income tax purposes (7) (8) Other 9 (5) Income tax expense 289 234 Effective tax rate (%) 16.0 14.3 |
Summary of Operating Loss Carryforwards | Income Tax Carryforwards ($ millions) Expiring Year 2022 Canadian Non-capital loss 2028-2042 393 Foreign Federal and state net operating loss (1) 2023-2042 3,093 Other tax credits 2023-2042 131 3,224 Total income tax carryforwards recognized 3,617 (1) Indefinite carryforward for Federal net operating losses, and for states that have adopted the Federal provisions, effective for tax years beginning after December 31, 2017 |
Summary of Tax Carryforward Amounts | Income Tax Carryforwards ($ millions) Expiring Year 2022 Canadian Non-capital loss 2028-2042 393 Foreign Federal and state net operating loss (1) 2023-2042 3,093 Other tax credits 2023-2042 131 3,224 Total income tax carryforwards recognized 3,617 (1) Indefinite carryforward for Federal net operating losses, and for states that have adopted the Federal provisions, effective for tax years beginning after December 31, 2017 |
Employee Future Benefits (Table
Employee Future Benefits (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
Schedule of Allocation of Plan Assets | Allocation of Plan Assets 2022 Target Allocation (weighted average %) 2022 2021 Equities 47 48 48 Fixed income 46 43 45 Real estate 6 8 6 Cash and other 1 1 1 100 100 100 Fair Value of Plan Assets ($ millions) Level 1 (1) Level 2 (1) Level 3 (1) Total 2022 Equities 666 1,005 — 1,671 Fixed income 199 1,289 — 1,488 Real estate — — 264 264 Private equities — — 18 18 Cash and other 5 22 — 27 870 2,316 282 3,468 2021 Equities 749 1,271 — 2,020 Fixed income 219 1,642 — 1,861 Real estate — — 235 235 Private equities — — 21 21 Cash and other 10 15 — 25 978 2,928 256 4,162 (1) See Note 25 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. ($ millions) 2022 2021 Balance, beginning of year 256 224 Return on plan assets 28 32 Foreign currency translation 3 — Purchases, sales and settlements (5) — Balance, end of year 282 256 |
Schedule of Amounts Recognized in Balance Sheet | Funded Status Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Change in benefit obligation (1) Balance, beginning of year 3,922 3,995 747 789 Service costs 106 109 35 35 Employee contributions 18 18 3 2 Interest costs 114 98 21 19 Benefits paid (195) (170) (29) (25) Actuarial gains (1,026) (111) (225) (70) Past service costs (credits)/plan amendments — (2) 1 — Foreign currency translation 124 (15) 29 (3) Balance, end of year (2) 3,063 3,922 582 747 Change in value of plan assets Balance, beginning of year 3,722 3,528 440 391 Actual return on plan assets (651) 291 (77) 48 Benefits paid (187) (158) (24) (21) Employee contributions 18 18 3 2 Employer contributions 54 55 19 22 Foreign currency translation 123 (12) 28 (2) Balance, end of year 3,079 3,722 389 440 Funded status 16 (200) (193) (307) Balance sheet presentation Other assets (Note 9) 188 204 86 55 Other current liabilities (Note 13) (15) (13) (13) (13) Other liabilities (Note 16) (157) (391) (266) (349) 16 (200) (193) (307) (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 $2,818 million as at December 31, 2022 (2021 - $3,586 million). |
Schedule of Funded Status | Funded Status Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Change in benefit obligation (1) Balance, beginning of year 3,922 3,995 747 789 Service costs 106 109 35 35 Employee contributions 18 18 3 2 Interest costs 114 98 21 19 Benefits paid (195) (170) (29) (25) Actuarial gains (1,026) (111) (225) (70) Past service costs (credits)/plan amendments — (2) 1 — Foreign currency translation 124 (15) 29 (3) Balance, end of year (2) 3,063 3,922 582 747 Change in value of plan assets Balance, beginning of year 3,722 3,528 440 391 Actual return on plan assets (651) 291 (77) 48 Benefits paid (187) (158) (24) (21) Employee contributions 18 18 3 2 Employer contributions 54 55 19 22 Foreign currency translation 123 (12) 28 (2) Balance, end of year 3,079 3,722 389 440 Funded status 16 (200) (193) (307) Balance sheet presentation Other assets (Note 9) 188 204 86 55 Other current liabilities (Note 13) (15) (13) (13) (13) Other liabilities (Note 16) (157) (391) (266) (349) 16 (200) (193) (307) (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 $2,818 million as at December 31, 2022 (2021 - $3,586 million). |
Schedule of Net Benefit Costs | Net Benefit Cost (1) Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Service costs 106 109 35 35 Interest costs 114 98 21 19 Expected return on plan assets (194) (177) (23) (19) Amortization of actuarial losses (gains) 4 36 (10) (2) Amortization of past service credits/plan amendments (1) (1) (1) (1) Regulatory adjustments (10) (1) 4 3 19 64 26 35 (1) The non-service benefit 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 ($ millions) 2022 2021 2022 2021 Unamortized net actuarial losses (gains) 9 33 (11) (5) Unamortized past service costs 1 1 7 7 Income tax (recovery) expense (2) (8) 1 — Accumulated other comprehensive income 8 26 (3) 2 Net actuarial losses (gains) 103 260 (195) (81) Past service credits (4) (5) (4) (6) Other regulatory deferrals (6) 10 7 14 93 265 (192) (73) Regulatory assets (Note 8) 207 376 — 12 Regulatory liabilities (Note 8) (114) (111) (192) (85) Net regulatory assets (liabilities) 93 265 (192) (73) |
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 liabilities. Defined Benefit OPEB Plans ($ millions) 2022 2021 2022 2021 Current year net actuarial gains (23) (10) (6) (4) Amortization of actuarial losses 1 1 — — Foreign currency translation (2) — — — Income tax expense 6 2 1 1 Total recognized in comprehensive income (18) (7) (5) (3) Current year net actuarial gains (155) (220) (118) (95) Past service cost/plan amendments — — 1 — Amortization of actuarial (losses) gains (6) (35) 10 2 Amortization of past service credits 1 2 1 2 Foreign currency translation 4 (2) (6) — Regulatory adjustments (16) (3) (7) (4) Total recognized in regulatory liabilities (172) (258) (119) (95) |
Schedule of Assumptions Used | Significant Assumptions Defined Benefit OPEB Plans (weighted average %) 2022 2021 2022 2021 Discount rate during the year (1) 2.97 2.60 2.97 2.60 Discount rate as at December 31 5.27 3.00 5.36 2.97 Expected long-term rate of return on plan assets (2) 5.87 5.40 5.00 4.88 Rate of compensation increase 3.33 3.30 — — Health care cost trend increase as at December 31 (3) — — 4.48 4.49 (1) ITC and UNS Energy 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 ($ millions) Pension Payments Payments 2023 $ 177 $ 30 2024 183 32 2025 190 33 2026 197 35 2027 203 35 2028-2032 1,094 191 |
Supplementary Cash Flow Infor_2
Supplementary Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | ($ millions) 2022 2021 Cash paid (received) for Interest 1,057 986 Income taxes 79 (13) Change in working capital Accounts receivable and other current assets (479) (88) Prepaid expenses (22) (15) Inventories (153) (56) Regulatory assets - current portion (307) (99) Accounts payable and other current liabilities 449 164 Regulatory liabilities - current portion 33 (50) (479) (144) Non-cash investing and financing activities Accrued capital expenditures 411 432 Common share dividends reinvested 364 356 Contributions in aid of construction 13 13 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments and Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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. ($ millions) Level 1 (1) Level 2 (1) Level 3 (1) Total As at December 31, 2022 Assets Energy contracts subject to regulatory deferral (2) (3) — 304 — 304 Energy contracts not subject to regulatory deferral (2) — 49 — 49 Other investments (4) 150 — — 150 150 353 — 503 Liabilities Energy contracts subject to regulatory deferral (3) (5) — (164) — (164) Energy contracts not subject to regulatory deferral (5) — (8) — (8) Foreign exchange contracts, total return and cross-currency interest rate swaps (5) — (26) — (26) — (198) — (198) As at December 31, 2021 Assets Energy contracts subject to regulatory deferral (2) (3) — 78 — 78 Energy contracts not subject to regulatory deferral (2) — 16 — 16 Foreign exchange contracts, total return and interest rate swaps (2) 23 2 — 25 Other investments (4) 137 — — 137 160 96 — 256 Liabilities Energy contracts subject to regulatory deferral (3) (5) — (46) — (46) Energy contracts not subject to regulatory deferral (5) — (3) — (3) — (49) — (49) (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 cash and cash equivalents and 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. ($ millions) Gross Amount Counterparty Cash Collateral Net Amount As at December 31, 2022 Derivative assets 353 54 63 236 Derivative liabilities (172) (54) — (118) As at December 31, 2021 Derivative assets 94 25 7 62 Derivative liabilities (49) (25) — (24) |
Derivative Liability Contracts Under Master Netting Agreements and Collateral Positions | The following table presents the potential offset of counterparty netting. ($ millions) Gross Amount Counterparty Cash Collateral Net Amount As at December 31, 2022 Derivative assets 353 54 63 236 Derivative liabilities (172) (54) — (118) As at December 31, 2021 Derivative assets 94 25 7 62 Derivative liabilities (49) (25) — (24) |
Schedule of Volume of Derivative Activity | As at December 31, 2022, 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. 2022 2021 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 586 509 Electricity power purchase contracts (GWh) 224 731 Gas swap contracts (PJ) 185 151 Gas supply contract premiums (PJ) 148 144 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 1,886 1,886 Gas swap contracts (PJ) 34 29 (1) GWh means gigawatt hours and PJ means petajoules |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Consolidated Commitments in the Next Five Years and Periods Thereafter | As at December 31, 2022, unconditional minimum purchase obligations were as follows. ($ millions) Total Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Gas and fuel purchase obligations (1) 5,720 1,024 516 461 374 328 3,017 Waneta Expansion capacity agreement (2) 2,472 54 55 56 58 59 2,190 Renewable PPAs (3) 1,926 131 131 131 131 130 1,272 Power purchase obligations (4) 1,691 334 253 191 192 113 608 ITC easement agreement (5) 380 14 14 14 14 14 310 Debt collection agreement (6) 106 3 3 3 3 3 91 Renewable energy credit purchase agreements (7) 77 18 14 7 7 6 25 Other (8) 132 21 9 20 3 3 76 12,504 1,599 995 883 782 656 7,589 (1) FortisBC Energy ($4,804 million): includes contracts of $2,720 million for the purchase of renewable natural gas expiring in 2044 and contracts of $2,084 million for the purchase of gas, renewable 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, 2022. The renewable gas supply obligations disclosed reflect the contracted price per GJ between the Corporation and the suppliers. UNS Energy ($801 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, the purchase of transmission services for purchased power, as well as natural gas commodity agreements based on projected market prices as of December 31, 2022. 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. (2) FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion hydroelectric generating facility for forty-years, beginning April 2015. (3) TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2051, 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. (4) Maritime Electric ($746 million): includes an energy purchase agreement and transmission capacity contract for 30 MW of capacity to PEI with New Brunswick Power, expiring December 2026 and November 2032, respectively. The agreements entitle Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and require Maritime Electric to pay its share of the station's capital operating costs for the life of the unit. FortisOntario ($489 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 ($258 million): includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning October 1, 2013. UNS Energy ($153 million): an agreement with Salt River Project Agricultural Improvement and Power District to purchase up to 300 MW of capacity, power and ancillary services through 2023. TEP will pay monthly capacity charges and variable power charges. (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 licenses 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, are collected in customer rates. (7) UNS Energy and Central Hudson are party to REC 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 AROs and joint-use asset and shared service agreements. |
Description of Business - Regul
Description of Business - Regulated Utilities (Details) | Dec. 31, 2022 community station company MW |
Wataynikaneyap Partnership | |
Public Utilities, General Disclosures [Line Items] | |
Equity investment ownership (percent) | 39% |
Belize Electricity | |
Public Utilities, General Disclosures [Line Items] | |
Equity investment ownership (percent) | 33% |
TEP and UNS Electric | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 3,328 |
TEP and UNS Electric | Solar | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 68 |
TEP and UNS Electric | Wind | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 250 |
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) | 90 |
FortisOntario | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 5 |
Number of utilities | company | 3 |
Fortis | Wataynikaneyap Partnership | |
Public Utilities, General Disclosures [Line Items] | |
Partnership with First Nation communities, number | community | 24 |
Caribbean Utilities | Diesel | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 166 |
Fortis Turks and Caicos | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 86 |
Number of utilities | company | 2 |
Fortis Turks and Caicos | Solar | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 2 |
Fortis Turks and Caicos | Diesel | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 84 |
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% |
Description of Business - Non-R
Description of Business - Non-Regulated (Details) | 12 Months Ended |
Dec. 31, 2022 station MW Bcf | |
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 (billions of cubic feet) | Bcf | 77 |
Regulation - Nature of Regulati
Regulation - Nature of Regulation Schedule (Details) - company | 1 Months Ended | 12 Months Ended | |||
Jul. 01, 2021 | Mar. 31, 2022 | Jul. 01, 2024 | Dec. 31, 2022 | Dec. 31, 2021 | |
ITC | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved cost-based formula, annual true-up (period) | 2 years | ||||
FortisOntario | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Number of utilities | 3 | ||||
Franchise agreement term | 35 years | ||||
FortisOntario | Electric Utilities, Following COS Regulation | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Number of utilities | 2 | ||||
Fortis Turks and Caicos | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Number of utilities | 2 | ||||
FERC | ITC | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 60% | ||||
Allowed ROE (percent) | 10.77% | 10.77% | |||
Approved cost-based formula, annual true-up (period) | 2 years | ||||
FERC | TEP | US Federal Energy Regulatory Commission Transmission Rates | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed ROE (percent) | 9.79% | ||||
ACC | TEP | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 53% | ||||
Allowed ROE (percent) | 9.15% | 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% | 49% | |||
Allowed ROE (percent) | 9% | 9% | |||
Common equity component of capital structure, approved rate decrease (percent) | 1% | ||||
PSC | Central Hudson | Forecast | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 48% | ||||
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% | ||||
Allowed ROE (percent) | 9.15% | 9.15% | |||
AUC | FortisAlberta | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 37% | ||||
Allowed ROE (percent) | 8.50% | 8.50% | |||
Newfoundland and Labrador Board of Commissioners of Public Utilities | Newfoundland Power | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 45% | ||||
Allowed ROE (percent) | 8.50% | 8.50% | |||
Island Regulatory and Appeals Commission | Maritime Electric | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 40% | ||||
Allowed ROE (percent) | 9.35% | 9.35% | |||
Ontario Energy Board | FortisOntario | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed common equity (percent) | 40% | ||||
Ontario Energy Board | FortisOntario | Minimum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed ROE (percent) | 8.52% | 8.52% | |||
Ontario Energy Board | FortisOntario | Maximum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed ROE (percent) | 9.30% | 9.30% | |||
Utility Regulation and Competition Office | Caribbean Utilities | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Transmission and distribution license period | 20 years | ||||
Non-exclusive generation license period | 25 years | ||||
Utility Regulation and Competition Office | Caribbean Utilities | Minimum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed ROA (percent) | 6.25% | 6% | |||
Utility Regulation and Competition Office | Caribbean Utilities | Maximum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Allowed ROA (percent) | 8.25% | 8% | |||
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% | 15% | |||
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 - Significant Regula
Regulation - Significant Regulatory Developments Narrative (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jun. 30, 2022 USD ($) | May 31, 2022 | Mar. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 CAD ($) | |
ACC | TEP | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Capital structure of common equity (percent) | 53% | ||||
ROE (percent) | 9.15% | 9.15% | |||
AUC | FortisAlberta | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Capital structure of common equity (percent) | 37% | ||||
ROE (percent) | 8.50% | 8.50% | |||
ITC Midwest Capital Structure Complaint | FERC | ITC Midwest | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Capital structure of common equity (percent) | 60% | ||||
Complaint, proposed reduction of equity component of capital structure | 53% | ||||
TEP General Rate Application | ACC | TEP | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Requested increase in non-fuel revenue | $ 136 | ||||
2023 General Cost Of Capital Proceeding | AUC | FortisAlberta | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Capital structure of common equity (percent) | 37% | ||||
ROE (percent) | 8.50% | ||||
Rural Electrification Association Cost Recovery | AUC | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Disallowed cost recovery, annual amount | $ 10 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Debt component of AFUDC | $ 45 | $ 39 |
Property, plant and equipment, weighted average composite depreciation rate | 2.70% | 2.60% |
Property, plant and equipment, generation remaining service life | 22 years | 23 years |
Property, plant and equipment, other weighted average remaining service life | 11 years | 13 years |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution weighted average remaining service life | 31 years | 32 years |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution weighted average remaining service life | 39 years | 38 years |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission weighted average remaining service life | 41 years | 42 years |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission weighted average remaining service life | 35 years | 35 years |
Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 0.50% | 0.90% |
Property, plant and equipment, generation service life | 5 years | 5 years |
Property, plant and equipment, other service life | 3 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 | 18 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 | 10 years |
Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 39.80% | 39.80% |
Property, plant and equipment, generation service life | 95 years | 95 years |
Property, plant and equipment, other service life | 80 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, 2022 | Dec. 31, 2021 | |
Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 5 years | 4 years |
Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 54 years | 55 years |
Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 11 years | 11 years |
Minimum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible assets, straight line depreciation rate | 1% | 1% |
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 | 34 years | 34 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% | 33% |
Maximum | Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 15 years | 15 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, 2022 numberOfReportingUnits | |
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, 2022 | Dec. 31, 2021 | |
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 | |
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) | $ 54.65 | $ 61.08 |
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) | $ 54.65 | 61.08 |
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) | $ 54.65 | $ 61.08 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Foreign Currency Translation (Details) - $ / $ | Dec. 31, 2022 | Dec. 31, 2021 |
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items] | ||
Foreign exchange rate (CAD per USD) | 1.36 | 1.26 |
Average | ||
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items] | ||
Foreign exchange rate (CAD per USD) | 1.30 | 1.25 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Income Taxes (Details) - CAD ($) $ in Billions | Dec. 31, 2022 | Dec. 31, 2021 |
Accounting Policies [Abstract] | ||
Undistributed earnings on foreign subsidiaries | $ 5.3 | $ 4.1 |
Segmented Information - Related
Segmented Information - Related-party and Inter-Company Transactions (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | ||
Related party transactions | $ 0 | $ 0 |
Inter-segment loans | 0 | 126,000,000 |
Belize Electricity | Equity Method Investee | ||
Related Party Transaction [Line Items] | ||
Due from related party | 7,000,000 | 22,000,000 |
Aitken Creek | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | $ 37,000,000 | $ 38,000,000 |
Segmented Information - Informa
Segmented Information - Information by Reportable Segment (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Segment Reporting Information [Line Items] | |||
Revenue | $ 11,043 | $ 9,448 | |
Energy supply costs | 3,952 | 2,951 | |
Operating expenses | 2,683 | 2,523 | |
Depreciation and amortization | 1,668 | 1,505 | |
Operating income | 2,740 | 2,469 | |
Other income, net | 165 | 173 | |
Finance charges | 1,102 | 1,003 | |
Income tax expense | 289 | 234 | |
Net earnings | 1,514 | 1,405 | |
Non-controlling interests | 120 | 111 | |
Preference share dividends | 64 | 63 | |
Common equity shareholders | 1,330 | 1,231 | |
Additions to property, plant and equipment and intangible assets | 3,865 | 3,386 | |
Goodwill | 12,464 | 11,720 | $ 11,792 |
Total assets | 64,252 | 57,659 | |
Intersegment eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenue | 0 | 0 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 0 | 0 | |
Depreciation and amortization | 0 | 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 | |
Additions to property, plant and equipment and intangible assets | 0 | 0 | |
Goodwill | 0 | 0 | |
Total assets | (12) | (148) | |
Regulated | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Revenue | 10,892 | 9,350 | |
Energy supply costs | 3,947 | 2,948 | |
Operating expenses | 2,623 | 2,453 | |
Depreciation and amortization | 1,649 | 1,485 | |
Operating income | 2,673 | 2,464 | |
Other income, net | 176 | 141 | |
Finance charges | 936 | 860 | |
Income tax expense | 356 | 320 | |
Net earnings | 1,557 | 1,425 | |
Non-controlling interests | 120 | 111 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 1,437 | 1,314 | |
Additions to property, plant and equipment and intangible assets | 3,836 | 3,366 | |
Goodwill | 12,437 | 11,693 | |
Total assets | 63,221 | 56,735 | |
Regulated | Operating Segments | ITC | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,906 | 1,691 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 481 | 466 | |
Depreciation and amortization | 385 | 291 | |
Operating income | 1,040 | 934 | |
Other income, net | 48 | 42 | |
Finance charges | 349 | 300 | |
Income tax expense | 184 | 156 | |
Net earnings | 555 | 520 | |
Non-controlling interests | 101 | 94 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 454 | 426 | |
Additions to property, plant and equipment and intangible assets | 1,212 | 1,046 | |
Goodwill | 8,318 | 7,755 | |
Total assets | 23,478 | 21,020 | |
Regulated | Operating Segments | UNS Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 2,758 | 2,334 | |
Energy supply costs | 1,213 | 919 | |
Operating expenses | 691 | 648 | |
Depreciation and amortization | 365 | 345 | |
Operating income | 489 | 422 | |
Other income, net | 22 | 41 | |
Finance charges | 127 | 120 | |
Income tax expense | 56 | 51 | |
Net earnings | 328 | 292 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 328 | 292 | |
Additions to property, plant and equipment and intangible assets | 709 | 710 | |
Goodwill | 1,873 | 1,746 | |
Total assets | 12,678 | 11,126 | |
Regulated | Operating Segments | Central Hudson | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,325 | 1,000 | |
Energy supply costs | 525 | 285 | |
Operating expenses | 571 | 498 | |
Depreciation and amortization | 104 | 91 | |
Operating income | 125 | 126 | |
Other income, net | 59 | 34 | |
Finance charges | 53 | 46 | |
Income tax expense | 28 | 21 | |
Net earnings | 103 | 93 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 103 | 93 | |
Additions to property, plant and equipment and intangible assets | 293 | 291 | |
Goodwill | 612 | 570 | |
Total assets | 5,131 | 4,356 | |
Regulated | Operating Segments | FortisBC Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 2,084 | 1,715 | |
Energy supply costs | 1,055 | 713 | |
Operating expenses | 364 | 355 | |
Depreciation and amortization | 298 | 281 | |
Operating income | 367 | 366 | |
Other income, net | 22 | 12 | |
Finance charges | 146 | 144 | |
Income tax expense | 39 | 48 | |
Net earnings | 204 | 186 | |
Non-controlling interests | 1 | 1 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 203 | 185 | |
Additions to property, plant and equipment and intangible assets | 589 | 475 | |
Goodwill | 913 | 913 | |
Total assets | 8,875 | 8,135 | |
Regulated | Operating Segments | FortisAlberta | |||
Segment Reporting Information [Line Items] | |||
Revenue | 680 | 644 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 166 | 157 | |
Depreciation and amortization | 243 | 231 | |
Operating income | 271 | 256 | |
Other income, net | 5 | 2 | |
Finance charges | 110 | 106 | |
Income tax expense | 15 | 11 | |
Net earnings | 151 | 141 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 151 | 141 | |
Additions to property, plant and equipment and intangible assets | 510 | 389 | |
Goodwill | 228 | 228 | |
Total assets | 5,547 | 5,201 | |
Regulated | Operating Segments | FortisBC Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 487 | 468 | |
Energy supply costs | 141 | 136 | |
Operating expenses | 133 | 128 | |
Depreciation and amortization | 67 | 65 | |
Operating income | 146 | 139 | |
Other income, net | 6 | 5 | |
Finance charges | 76 | 73 | |
Income tax expense | 12 | 12 | |
Net earnings | 64 | 59 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 64 | 59 | |
Additions to property, plant and equipment and intangible assets | 130 | 134 | |
Goodwill | 235 | 235 | |
Total assets | 2,596 | 2,540 | |
Regulated | Operating Segments | Other Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,652 | 1,498 | |
Energy supply costs | 1,013 | 895 | |
Operating expenses | 217 | 201 | |
Depreciation and amortization | 187 | 181 | |
Operating income | 235 | 221 | |
Other income, net | 14 | 5 | |
Finance charges | 75 | 71 | |
Income tax expense | 22 | 21 | |
Net earnings | 152 | 134 | |
Non-controlling interests | 18 | 16 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 134 | 118 | |
Additions to property, plant and equipment and intangible assets | 393 | 321 | |
Goodwill | 258 | 246 | |
Total assets | 4,916 | 4,357 | |
Non-Regulated | Operating Segments | Energy Infrastructure | |||
Segment Reporting Information [Line Items] | |||
Revenue | 151 | 98 | |
Energy supply costs | 5 | 3 | |
Operating expenses | 40 | 33 | |
Depreciation and amortization | 17 | 17 | |
Operating income | 89 | 45 | |
Other income, net | 1 | 1 | |
Finance charges | 0 | 0 | |
Income tax expense | 18 | 8 | |
Net earnings | 72 | 38 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 72 | 38 | |
Additions to property, plant and equipment and intangible assets | 29 | 20 | |
Goodwill | 27 | 27 | |
Total assets | 884 | 777 | |
Non-Regulated | Operating Segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Revenue | 0 | 0 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 20 | 37 | |
Depreciation and amortization | 2 | 3 | |
Operating income | (22) | (40) | |
Other income, net | (12) | 31 | |
Finance charges | 166 | 143 | |
Income tax expense | (85) | (94) | |
Net earnings | (115) | (58) | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 64 | 63 | |
Common equity shareholders | (179) | (121) | |
Additions to property, plant and equipment and intangible assets | 0 | 0 | |
Goodwill | 0 | 0 | |
Total assets | $ 159 | $ 295 |
Revenue - Schedule of Revenue (
Revenue - Schedule of Revenue (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 10,912 | $ 9,252 |
Alternative revenue | (28) | (18) |
Other revenue | 159 | 214 |
Revenues | 11,043 | 9,448 |
Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 10,503 | 8,870 |
Other services revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 409 | 382 |
Other services revenue | Regulated Operation | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 266 | 260 |
ITC | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,911 | 1,694 |
UNS Energy | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 2,498 | 2,071 |
Central Hudson | United States | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 1,307 | 962 |
FortisBC Energy | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 2,080 | 1,645 |
FortisAlberta | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 655 | 622 |
FortisBC Electric | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 429 | 404 |
Newfoundland Power | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 722 | 701 |
Maritime Electric | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 234 | 223 |
FortisOntario | Canada | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 220 | 211 |
Caribbean Utilities | Caribbean | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | 349 | 248 |
FortisTCI | Caribbean | Electric and gas revenue | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contracts with customers | $ 98 | $ 89 |
Revenue - Narrative (Details)
Revenue - Narrative (Details) | 12 Months Ended |
Dec. 31, 2022 | |
ITC | |
Disaggregation of Revenue [Line Items] | |
True-up period | 2 years |
UNS Energy | |
Disaggregation of Revenue [Line Items] | |
Year over year recovery cap (percent) | 2% |
FortisBC Energy and FortisBC Electric | |
Disaggregation of Revenue [Line Items] | |
Variance sharing (percent) | 50% |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Receivables [Abstract] | |||
Trade accounts receivable | $ 930 | $ 621 | |
Unbilled accounts receivable | 887 | 701 | |
Allowance for credit losses | (58) | (53) | $ (64) |
Total accounts receivable | 1,759 | 1,269 | |
Other | 580 | 242 | |
Accounts receivable and other current assets | $ 2,339 | $ 1,511 |
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, 2022 | Dec. 31, 2021 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance, beginning of year | $ (53) | $ (64) |
Credit loss expensed | (27) | (7) |
Credit loss deferred | (6) | 0 |
Write-offs, net of recoveries | 30 | 18 |
Foreign exchange | (2) | 0 |
Balance, end of year | $ (58) | $ (53) |
Inventories (Details)
Inventories (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 661 | $ 478 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 394 | 318 |
Gas and fuel in storage | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 235 | 131 |
Coal inventory | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 32 | $ 29 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 4,009 | $ 3,589 |
Less: Current portion | (914) | (492) |
Long-term regulatory assets | 3,095 | 3,097 |
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 3,915 | 3,222 |
Less: Current portion | (595) | (357) |
Long-term regulatory liabilities | 3,320 | 2,865 |
Deferred income taxes (Note 3) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,364 | 1,289 |
Future cost of removal (Note 3) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 1,306 | 1,217 |
Employee future benefits (Notes 3 and 23) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 306 | 196 |
Rate stabilization and related accounts | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 297 | 116 |
Derivatives (Notes 3 and 25) | Energy contracts subject to regulatory deferral | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 224 | 52 |
Renewable energy surcharge | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 126 | 107 |
Renewable energy surcharge | UNS Energy | ||
Regulatory Liabilities [Line Items] | ||
Renewable energy target (at least) (percent) | 15% | |
Energy efficiency liability | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 89 | 83 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 203 | 162 |
Other regulatory liabilities, individually less than threshold | ||
Regulatory Liabilities [Line Items] | ||
Threshold amount, other regulatory liabilities | 40 | |
Deferred income taxes (Note 3) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,874 | 1,806 |
Rate stabilization and related accounts | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 557 | 339 |
Deferred energy management costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 445 | 384 |
Deferred energy management costs | Minimum | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period | 1 year | |
Deferred energy management costs | Maximum | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period | 10 years | |
Employee future benefits (Notes 3 and 23) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 207 | 388 |
Deferred lease costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 132 | 127 |
Manufactured gas plant site remediation deferral (Note 16) | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 97 | 96 |
Deferred storm costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 91 | 17 |
Derivatives (Notes 3 and 25) | Energy contracts subject to regulatory deferral | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 84 | 20 |
Generation early retirement costs | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 78 | 48 |
Other | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 444 | $ 364 |
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, 2022 | Dec. 31, 2021 |
Regulated Operations [Abstract] | ||
Regulatory assets not earning a return | $ 1,980 | $ 1,727 |
Other Assets - Schedule of Othe
Other Assets - Schedule of Other Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Employee future benefits (Note 23) | $ 274 | $ 259 |
Equity investments | 201 | 92 |
Supplemental Executive Retirement Plan ("SERP") | 155 | 165 |
RECs (Note 8) | 142 | 112 |
Derivatives | 118 | 40 |
Other investments | 115 | 86 |
Operating leases (Note 15) | 43 | 40 |
Deferred compensation plan | 40 | 42 |
Other | 125 | 119 |
Other assets | $ 1,213 | $ 955 |
Property, Plant And Equipment -
Property, Plant And Equipment - Schedule of Utility Capital Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | $ 56,167 | $ 51,190 |
Accumulated Depreciation | (14,504) | (13,374) |
Net Book Value | 41,663 | 37,816 |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 13,650 | 12,321 |
Accumulated Depreciation | (3,715) | (3,359) |
Net Book Value | 9,935 | 8,962 |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 6,396 | 5,838 |
Accumulated Depreciation | (1,626) | (1,504) |
Net Book Value | 4,770 | 4,334 |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 19,056 | 17,104 |
Accumulated Depreciation | (4,074) | (3,610) |
Net Book Value | 14,982 | 13,494 |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 2,600 | 2,453 |
Accumulated Depreciation | (800) | (756) |
Net Book Value | 1,800 | 1,697 |
Generation | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 7,173 | 7,014 |
Accumulated Depreciation | (2,679) | (2,691) |
Net Book Value | 4,494 | 4,323 |
Other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 4,803 | 4,362 |
Accumulated Depreciation | (1,610) | (1,454) |
Net Book Value | 3,193 | 2,908 |
Assets under construction | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 2,094 | 1,759 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | 2,094 | 1,759 |
Land | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 395 | 339 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | $ 395 | $ 339 |
Property, Plant And Equipment_2
Property, Plant And Equipment - Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 CAD ($) kPa kV | Dec. 31, 2021 CAD ($) | |
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% | |
Electric transmission capacity, above (kV) | kV | 69 | |
Gas transmission capacity, above (kPa) | kPa | 2,070 | |
Gas transmission capacity, hoop stress, or more (percent) | 20% | |
Cost of PPE under finance leases | $ | $ 323 | $ 323 |
Cost of PPE under finance leases, accumulated depreciation | $ | $ 117 | $ 113 |
Property, Plant And Equipment_3
Property, Plant And Equipment - Schedule of Jointly-Owned Utility Plants (Details) $ in Millions | Dec. 31, 2022 CAD ($) |
Jointly Owned Facilities [Line Items] | |
Cost | $ 2,617 |
Accumulated Depreciation | (1,017) |
Net Book Value | 1,600 |
Transmission Facilities | |
Jointly Owned Facilities [Line Items] | |
Cost | 1,333 |
Accumulated Depreciation | (428) |
Net Book Value | $ 905 |
Springerville Common Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 86% |
Cost | $ 544 |
Accumulated Depreciation | (294) |
Net Book Value | $ 250 |
Springerville Coal Handling Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 83% |
Cost | $ 281 |
Accumulated Depreciation | (133) |
Net Book Value | $ 148 |
Four Corners Units 4 and 5 ("Four Corners") | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 7% |
Cost | $ 264 |
Accumulated Depreciation | (119) |
Net Book Value | $ 145 |
Gila River Common Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 50% |
Cost | $ 118 |
Accumulated Depreciation | (43) |
Net Book Value | $ 75 |
Luna Energy Facility ("Luna") | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 33.30% |
Cost | $ 77 |
Accumulated Depreciation | 0 |
Net Book Value | $ 77 |
Intangible Assets - Schedule of
Intangible Assets - Schedule of Intangible Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | $ 2,294 | $ 2,084 |
Accumulated Amortization | (746) | (741) |
Net Book Value | 1,548 | 1,343 |
Land, transmission and water rights | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 1,064 | 941 |
Accumulated Amortization | (171) | (154) |
Net Book Value | 893 | 787 |
Assets under construction | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 110 | 78 |
Accumulated Amortization | 0 | 0 |
Net Book Value | 110 | 78 |
Computer software | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 985 | 952 |
Accumulated Amortization | (497) | (518) |
Net Book Value | 488 | 434 |
Other | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 135 | 113 |
Accumulated Amortization | (78) | (69) |
Net Book Value | $ 57 | $ 44 |
Intangible Assets - Narrative (
Intangible Assets - Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Amortization - intangible assets | $ 145 | $ 136 |
Amortization expense, next twelve months | 90 | |
Amortization expense, year two | 90 | |
Amortization expense, year three | 90 | |
Amortization expense, year four | 90 | |
Amortization expense, year five | 90 | |
Land, transmission and water rights | ||
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Cost not subject to amortization | $ 117 | $ 137 |
Goodwill (Details)
Goodwill (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Goodwill [Roll Forward] | ||
Balance, beginning of year | $ 11,720,000,000 | $ 11,792,000,000 |
Foreign currency translation impacts | 744,000,000 | (72,000,000) |
Balance, end of year | 12,464,000,000 | 11,720,000,000 |
Goodwill impairment loss | $ 0 | $ 0 |
Accounts Payable and Other Cu_3
Accounts Payable and Other Current Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Payables and Accruals [Abstract] | ||
Trade accounts payable | $ 886 | $ 774 |
Gas and fuel cost payable | 512 | 269 |
Customer and other deposits | 401 | 288 |
Accrued taxes other than income taxes | 282 | 238 |
Dividends payable | 278 | 259 |
Employee compensation and benefits payable | 270 | 283 |
Interest payable | 254 | 218 |
Derivatives (Note 25) | 127 | 43 |
Income taxes payable | 88 | 31 |
Employee future benefits (Note 23) | 28 | 26 |
Manufactured gas plant site remediation (Note 16) | 17 | 13 |
Other | 145 | 128 |
Accounts payable and other current liabilities | $ 3,288 | $ 2,570 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Instrument [Line Items] | ||
Total long-term debt | $ 28,578 | $ 25,482 |
Less: Deferred financing costs and debt discounts | (166) | (147) |
Less: Current installments of long-term debt | (2,481) | (1,628) |
Long-term debt | 25,931 | 23,707 |
Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | 1,657 | 1,305 |
Credit facility | ||
Debt Instrument [Line Items] | ||
Less: Current installments of long-term debt | $ (1,376) | $ (888) |
Long-term debt weighted average interest rate (percent) | 5.10% | 0.90% |
Credit facility | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 1,657 | $ 1,305 |
ITC | ||
Debt Instrument [Line Items] | ||
Fair value adjustment - ITC acquisition | 102 | 107 |
ITC | Secured | Fixed Rate Secured US First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 3,344 | $ 2,736 |
Long-term debt weighted average interest rate (percent) | 4.22% | 4.31% |
ITC | Secured | Fixed Rate Secured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 1,186 | $ 1,011 |
Long-term debt weighted average interest rate (percent) | 3.83% | 3.90% |
ITC | Unsecured | Fixed Rate Unsecured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 4,541 | $ 4,108 |
Long-term debt weighted average interest rate (percent) | 3.98% | 3.61% |
ITC | Unsecured | Fixed Rate Unsecured US Shareholder Note | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 270 | $ 252 |
Stated interest rate (percent) | 6% | 6% |
UNS Energy | Unsecured | Fixed and Variable Rate Unsecured US Tax-Exempt Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 123 | $ 359 |
Long-term debt weighted average interest rate (percent) | 4% | 4.34% |
UNS Energy | Unsecured | Fixed Rate Unsecured US Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 3,450 | $ 2,780 |
Long-term debt weighted average interest rate (percent) | 3.58% | 3.62% |
Central Hudson | Unsecured | Fixed and Variable Rate Unsecured US Promissory Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 1,526 | $ 1,177 |
Long-term debt weighted average interest rate (percent) | 4.14% | 3.83% |
FortisBC Energy | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 3,295 | $ 3,145 |
Long-term debt weighted average interest rate (percent) | 4.61% | 4.61% |
FortisAlberta | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,485 | $ 2,360 |
Long-term debt weighted average interest rate (percent) | 4.49% | 4.49% |
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 | $ 860 | $ 760 |
Long-term debt weighted average interest rate (percent) | 4.70% | 4.77% |
Other Electric | Secured | Fixed Rate Secured First Mortgage Sinking Fund Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 666 | $ 627 |
Long-term debt weighted average interest rate (percent) | 5.26% | 5.61% |
Other Electric | Secured | Fixed Rate Secured First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 260 | $ 260 |
Long-term debt weighted average interest rate (percent) | 5.31% | 5.31% |
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 (percent) | 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 | $ 745 | $ 609 |
Long-term debt weighted average interest rate (percent) | 4.71% | 4.36% |
Corporate and Other | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 200 | $ 200 |
Stated interest rate (percent) | 6.51% | 6.51% |
Corporate and Other | Unsecured | Fixed Rate Unsecured Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 1,000 | $ 1,000 |
Long-term debt weighted average interest rate (percent) | 3.31% | 2.52% |
Corporate and Other | Unsecured | Fixed Rate Unsecured US Senior Notes and Promissory Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 2,691 | $ 2,509 |
Long-term debt weighted average interest rate (percent) | 3.82% | 3.82% |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Nov. 30, 2022 CAD ($) | May 31, 2022 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) | May 31, 2022 USD ($) | Dec. 31, 2021 CAD ($) | Dec. 31, 2021 USD ($) | |
Debt Instrument [Line Items] | |||||||
Short-form base shelf prospectus, life | 25 months | ||||||
Short-form base shelf prospectus, principal amount, up to | $ 2,000 | ||||||
Short-form base shelf prospectus, remaining amount available | $ 2,000 | ||||||
Maximum borrowing capacity | 5,850 | $ 4,846 | |||||
Central Hudson | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 320 | $ 230 | |||||
Consolidated credit facilities | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 5,900 | ||||||
No one bank | Bank concentration risk | Credit facility | |||||||
Debt Instrument [Line Items] | |||||||
Concentration risk percentage | 20% | ||||||
Committed facilities with maturities ranging from 2023 through 2027 | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 5,600 | ||||||
Unsecured Revolving Committed Credit Facility, 2027 Maturity, Fortis | Fortis | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 1,300 | ||||||
Maximum potential annual margin pricing adjustments, funds drawn | 0.0005 | 0.0005 | |||||
Maximum potential annual margin pricing adjustments, funds undrawn | 0.0001 | 0.0001 | |||||
Unsecured Non-Revolving Term Credit Facility | Fortis | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 500 | ||||||
Debt instrument, term | 1 year | ||||||
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 | ||||||||||
Jun. 30, 2022 CAD ($) | Nov. 30, 2022 USD ($) | Nov. 30, 2022 CAD ($) | Oct. 31, 2022 USD ($) | Sep. 30, 2022 USD ($) | May 31, 2022 USD ($) | May 31, 2022 CAD ($) | Apr. 30, 2022 CAD ($) | Mar. 31, 2022 CAD ($) | Feb. 28, 2022 USD ($) | Jan. 31, 2022 USD ($) | |
Cross Currency Interest Rate Contract | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Notional amount of derivative | $ 391 | ||||||||||
ITC | Secured First Mortgage Bonds, January Issuance, 2052 Maturity | Secured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 2.93% | ||||||||||
Face value | $ 150 | ||||||||||
ITC | Secured Senior Notes, May Issuance, 2052 Maturity | Secured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 3.05% | 3.05% | |||||||||
Face value | $ 75 | ||||||||||
ITC | Unsecured Senior Notes, September Issuance, 2027 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.95% | ||||||||||
Face value | $ 600 | ||||||||||
Effective interest rate | 3.54% | ||||||||||
ITC | Secured First Mortgage Bonds, October Issuance, 2027 Maturity | Secured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 3.87% | ||||||||||
Face value | $ 75 | ||||||||||
ITC | Secured First Mortgage Bonds, October Issuance, 2052 Maturity | Secured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.53% | ||||||||||
Face value | $ 75 | ||||||||||
UNS Energy | Unsecured Senior Notes, February Issuance, 2032 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 3.25% | ||||||||||
Face value | $ 325 | ||||||||||
Central Hudson | Unsecured Senior Notes, January Issuance, 2027 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 2.37% | ||||||||||
Face value | $ 50 | ||||||||||
Central Hudson | Unsecured Senior Notes, January Issuance, 2029 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 2.59% | ||||||||||
Face value | $ 60 | ||||||||||
Central Hudson | Unsecured Senior Notes, September Issuance, 2032 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 5.07% | ||||||||||
Face value | $ 100 | ||||||||||
Central Hudson | Unsecured Senior Notes, September Issuance, 2052 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 5.42% | ||||||||||
Face value | $ 10 | ||||||||||
FortisBC Energy | Unsecured Senior Bond, November Issuance, 2052 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.67% | 4.67% | |||||||||
Face value | $ 150 | ||||||||||
FortisAlberta | Senior Unsecured Debentures, May Issuance, 2052 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.62% | 4.62% | |||||||||
Face value | $ 125 | ||||||||||
FortisBC Electric | Unsecured Debentures, March Issuance, 2052 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.16% | ||||||||||
Face value | $ 100 | ||||||||||
Newfoundland Power | First Mortgage Sinking Fund Bonds, April Issuance, 2052 Maturity | Secured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.20% | ||||||||||
Face value | $ 75 | ||||||||||
Caribbean Utilities | Unsecured Senior Notes, November Issuance, 2052 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 5.88% | 5.88% | |||||||||
Face value | $ 80 | ||||||||||
Fortis | Cross Currency Interest Rate Contract | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Notional amount of derivative | $ 391 | ||||||||||
Interest rate | 4.34% | 4.34% | |||||||||
Fortis | Unsecured Senior Notes, May Issuance, 2029 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 4.43% | 4.43% | |||||||||
Face value | $ 500 | ||||||||||
Fortis | Unsecured Senior Notes, 2023 Maturity | Unsecured | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Stated interest rate (percent) | 2.85% | ||||||||||
Repayments of long-term debt | $ 500 |
Long-Term Debt - Long-Term De_2
Long-Term Debt - Long-Term Debt Repayments (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Maturities of Long-term Debt [Abstract] | ||
2023 | $ 2,481 | |
2024 | 1,434 | |
2025 | 518 | |
2026 | 2,434 | |
2027 | 1,977 | |
Thereafter | 19,734 | |
Long-term Debt | $ 28,578 | $ 25,482 |
Long-Term Debt - Schedule of Cr
Long-Term Debt - Schedule of Credit Facilities (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Line of Credit Facility [Line Items] | ||
Total credit facilities | $ 5,850 | $ 4,846 |
Credit facilities utilized: | ||
Short-term borrowings | (253) | (247) |
Long-term debt (including current portion) | (28,578) | (25,482) |
Letters of credit outstanding | (128) | (115) |
Credit facilities unutilized | 3,812 | 3,179 |
Current installments of long-term debt | $ 2,481 | $ 1,628 |
Credit facility | ||
Credit facilities utilized: | ||
Long-term debt weighted average interest rate (percent) | 5.10% | 0.90% |
Current installments of long-term debt | $ 1,376 | $ 888 |
Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (1,657) | (1,305) |
Long-term Credit Facility Borrowings | Credit facility | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (1,657) | (1,305) |
Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | $ (253) | $ (247) |
Short-term debt weighted average interest rate (percent) | 4.90% | 0.60% |
Regulated Operation | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | $ 3,795 | |
Credit facilities utilized: | ||
Letters of credit outstanding | (76) | |
Credit facilities unutilized | 2,544 | |
Regulated Operation | Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (922) | |
Regulated Operation | Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | (253) | |
Corporate and Other | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | 2,055 | |
Credit facilities utilized: | ||
Letters of credit outstanding | (52) | |
Credit facilities unutilized | 1,268 | |
Corporate and Other | Long-term Credit Facility Borrowings | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (735) | |
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, 2022 CAD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 CAD ($) | Dec. 31, 2021 USD ($) |
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 5,850 | $ 4,846 | ||
Central Hudson | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 320 | $ 230 | ||
Regulated Operation | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 3,795 | |||
Regulated Operation | ITC | Commercial paper | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 400 | |||
Amount outstanding | 134 | $ 155 | ||
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 | 375 | |||
Regulated Operation | Central Hudson | Unsecured committed revolving credit facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 250 | |||
Regulated Operation | Central Hudson | Uncommitted credit facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 70 | |||
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 | 255 | 83 | ||
Regulated Operation | Other Electric | Unsecured committed revolving credit facility | First redemption date | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 65 | |||
Regulated Operation | Other Electric | Unsecured committed revolving credit facility | Second redemption date | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 90 | |||
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 | 2,055 | |||
Non-Regulated | Corporate and other | Unsecured committed revolving credit facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 1,350 | |||
Non-Regulated | Corporate and other | Unsecured committed revolving credit facility | First redemption date | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 50 | |||
Non-Regulated | Corporate and other | Unsecured committed revolving credit facility | Second redemption date | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 1,300 | |||
Non-Regulated | Corporate and other | Unsecured non-revolving facility | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 27 | |||
Non-Regulated | Corporate and other | Unsecured non-revolving facility, 2023 maturity | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | $ 500 |
Leases - Narrative (Details)
Leases - Narrative (Details) - Maximum | Dec. 31, 2022 |
Lessee, Lease, Description [Line Items] | |
Operating leases, remaining term (up to) | 25 years |
Finance leases, remaining term (up to) | 33 years |
Leases - Operating and Finance
Leases - Operating and Finance Lease Balance Sheet Location (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Operating leases | ||
Other assets | $ 43 | $ 40 |
Accounts payable and other current liabilities | (9) | (8) |
Other liabilities | (34) | (32) |
Finance leases | ||
Accounts payable and other current liabilities | (2) | (4) |
Finance leases | $ (336) | $ (333) |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other assets (Note 9) | Other assets (Note 9) |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Accounts payable and other current liabilities (Note 13) | Accounts payable and other current liabilities (Note 13) |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other Liabilities, Noncurrent | Other Liabilities, Noncurrent |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Public Utilities, Property, Plant and Equipment, Net, Regulatory assets (Note 8), Long-term regulatory assets | Public Utilities, Property, Plant and Equipment, Net, Regulatory assets (Note 8), Long-term regulatory assets |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | Accounts payable and other current liabilities (Note 13) | Accounts payable and other current liabilities (Note 13) |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Finance leases | Finance leases |
Regulatory assets | ||
Finance leases | ||
Finance lease assets | $ 132 | $ 127 |
PPE, net | ||
Finance leases | ||
Finance lease assets | $ 206 | $ 210 |
Leases - Lease Expenses (Detail
Leases - Lease Expenses (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | ||
Operating lease cost | $ 9 | $ 8 |
Finance lease cost: | ||
Amortization | 1 | 2 |
Interest | 33 | 32 |
Variable lease cost | 21 | 19 |
Total lease cost | $ 64 | $ 61 |
Leases - Present Value of Minim
Leases - Present Value of Minimum Lease Payments (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Operating Leases | ||
2023 | $ 10 | |
2024 | 9 | |
2025 | 6 | |
2026 | 5 | |
2027 | 3 | |
Thereafter | 19 | |
Total operating lease payments | 52 | |
Less: Imputed interest | (9) | |
Total lease obligations | 43 | |
Less: Current installments | (9) | $ (8) |
Operating leases (Note 15) | 34 | 32 |
Finance Leases | ||
2023 | 35 | |
2024 | 35 | |
2025 | 35 | |
2026 | 35 | |
2027 | 36 | |
Thereafter | 1,001 | |
Total finance lease payments | 1,177 | |
Less: Imputed interest | (839) | |
Total lease obligations | 338 | |
Less: Current installments | (2) | (4) |
Finance leases | 336 | $ 333 |
Total | ||
2023 | 45 | |
2024 | 44 | |
2025 | 41 | |
2026 | 40 | |
2027 | 39 | |
Thereafter | 1,020 | |
Total lease payments | 1,229 | |
Less: Imputed interest | (848) | |
Total lease obligations | 381 | |
Less: Current installments | (11) | |
Long-term lease obligations | $ 370 |
Leases - Supplemental Lease Inf
Leases - Supplemental Lease Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Weighted average remaining lease term (years) | ||
Operating leases | 9 years | 10 years |
Finance leases | 33 years | 34 years |
Weighted average discount rate (%) | ||
Operating leases | 4.10% | 3.80% |
Finance leases | 5% | 5.10% |
Cash payments related to lease liabilities | ||
Operating cash flows used for operating leases | $ (8) | $ (8) |
Financing cash flows used for finance leases | $ (1) | $ (2) |
Other Liabilities - Schedule of
Other Liabilities - Schedule of Other Liabilities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 CAD ($) mine | Dec. 31, 2020 | Dec. 31, 2021 CAD ($) | |
Other Commitments [Line Items] | |||
Employee future benefits (Note 23) | $ 423 | $ 740 | |
AROs (Note 3) | 174 | 184 | |
Customer and other deposits | 107 | 99 | |
Manufactured gas plant site remediation | 95 | 83 | |
Stock-based compensation plans (Note 20) | 79 | 96 | |
Derivatives (Note 25) | 72 | 7 | |
Deferred compensation plan (Note 9) | 48 | 50 | |
Mine reclamation obligations | 39 | 44 | |
Operating leases (Note 15) | 34 | 32 | |
Retail energy contract | 33 | 40 | |
Other | 42 | 34 | |
Other liabilities | 1,146 | 1,409 | |
Remediation cost obligation, current | 17 | $ 13 | |
Central Hudson | |||
Other Commitments [Line Items] | |||
Remediation cost obligation | 100 | ||
Remediation cost obligation, current | $ 5 | ||
TEP | Coal mine reclamation | |||
Other Commitments [Line Items] | |||
Number of mines | mine | 2 | ||
Environmental exit costs, estimated reclamation costs | $ 54 | ||
FortisAlberta | |||
Other Commitments [Line Items] | |||
Retail energy contract period | 8 years |
Earnings Per Common Share (Deta
Earnings Per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Net Earnings to Common Shareholders | ||
Basic EPS | $ 1,330 | $ 1,231 |
Potential dilutive effect of stock options | 0 | 0 |
Diluted EPS | $ 1,330 | $ 1,231 |
Weighted Average Shares | ||
Basic EPS (shares) | 478.6 | 470.9 |
Potential dilutive effect of stock options (shares) | 0.4 | 0.5 |
Diluted EPS (shares) | 479 | 471.4 |
EPS | ||
Basic (CAD per share) | $ 2.78 | $ 2.61 |
Diluted (CAD per share) | $ 2.78 | $ 2.61 |
Preference Shares - Issued and
Preference Shares - Issued and Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
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 | 7,665 |
Preferred stock issued | $ 188 | $ 188 |
Preferred stock outstanding (shares) | 7,665 | 7,665 |
Preferred stock outstanding | $ 188 | $ 188 |
Series I | ||
Class of Stock [Line Items] | ||
Preferred stock issued (shares) | 2,335 | 2,335 |
Preferred stock issued | $ 57 | $ 57 |
Preferred stock outstanding (shares) | 2,335 | 2,335 |
Preferred stock outstanding | $ 57 | $ 57 |
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) | 12 Months Ended |
Dec. 31, 2022 $ / shares | |
Series F | |
Class of Stock [Line Items] | |
Initial yield (percent) | 4.90% |
Annual Dividend (CAD per share) | $ 1.2250 |
Reset Dividend Yield (percent) | 0% |
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% |
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) | $ 0.4588 |
Reset Dividend Yield (percent) | 1.45% |
Redemption price (CAD per share) | $ 25 |
Preferred shares exchange ratio | 1 |
Series K | |
Class of Stock [Line Items] | |
Initial yield (percent) | 4% |
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% |
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% |
Annual Dividend (CAD per share) | $ 0 |
Reset Dividend Yield (percent) | 0% |
Redemption price (CAD per share) | $ 0 |
Preferred shares exchange ratio | 1 |
Series N | |
Class of Stock [Line Items] | |
Initial yield (percent) | 0% |
Annual Dividend (CAD per share) | $ 0 |
Reset Dividend Yield (percent) | 0% |
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 |
Preferred shares rate dividend term | 5 years |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Accumulated other comprehensive income | ||
Beginning balance | $ 19,288 | |
Ending balance | 21,030 | $ 19,288 |
Interest rate hedges | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (5) | (4) |
Other comprehensive income (loss), before tax | 54 | (1) |
Accumulated other comprehensive income (loss), before tax, ending balance | 49 | (5) |
Net investments in foreign operations | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | 273 | 377 |
Other comprehensive income (loss), before tax | 1,222 | (104) |
Accumulated other comprehensive income (loss), before tax, ending balance | 1,495 | 273 |
Hedges of net investments in foreign operations | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (276) | (299) |
Other comprehensive income (loss), before tax | (254) | 23 |
Accumulated other comprehensive income (loss), before tax, ending balance | (530) | (276) |
Net unrealized foreign currency translation gains (losses) | ||
Accumulated other comprehensive income | ||
Income tax recovery (expense), opening balance | (8) | (6) |
Beginning balance | (11) | 72 |
Other comprehensive income (loss), tax recovery (expense) | 15 | (2) |
Other comprehensive income (loss) | 983 | (83) |
Income tax recovery (expense), ending balance | 7 | (8) |
Ending balance | 972 | (11) |
Unrealized employee future benefits (losses) gains (Note 23) | ||
Accumulated other comprehensive income | ||
Accumulated other comprehensive income (loss), before tax, opening balance | (36) | (49) |
Other comprehensive income (loss), before tax | 30 | 13 |
Accumulated other comprehensive income (loss), before tax, ending balance | (6) | (36) |
Cash flow hedges and unrealized employee future benefits (losses) gains | ||
Accumulated other comprehensive income | ||
Income tax recovery (expense), opening balance | 12 | 15 |
Beginning balance | (29) | (38) |
Other comprehensive income (loss), tax recovery (expense) | (19) | (3) |
Other comprehensive income (loss) | 65 | 9 |
Income tax recovery (expense), ending balance | (7) | 12 |
Ending balance | 36 | (29) |
Accumulated other comprehensive income | ||
Accumulated other comprehensive income | ||
Beginning balance | (40) | 34 |
Other comprehensive income (loss) | 1,048 | (74) |
Ending balance | $ 1,008 | $ (40) |
Stock-based Compensation Plan_2
Stock-based Compensation Plans - Stock Options Narrative (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock options outstanding (shares) | 2.3 | 2.9 |
Stock options weighted average exercise price (CAD per share) | $ 47.72 | $ 47.20 |
Options vested, number of options (shares) | 1.5 | 1.4 |
Options vested, weighted average exercise price (CAD per share) | $ 44.86 | $ 42.76 |
Options exercised (shares) | 1 | 1 |
Proceeds from stock options exercised | $ 26 | $ 32 |
Stock options, intrinsic value | $ 9 | $ 11 |
Options | ||
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 - Directors' DSU Plan (Details) - Director - DSUs shares in Thousands | 12 Months Ended | |
Dec. 31, 2022 shares | Dec. 31, 2021 shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unit with underlying value equivalent to common shares | 1 | |
Number of units (thousands) | ||
DSUs outstanding, beginning of year (shares) | 183 | 147 |
Granted (shares) | 33 | 30 |
Notional dividends reinvested (shares) | 8 | 6 |
DSUs outstanding, end of year (shares) | 224 | 183 |
Stock-based Compensation Plan_4
Stock-based Compensation Plans - PSU Plans Narrative (Details) - PSUs | 12 Months Ended |
Dec. 31, 2022 | |
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% |
Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Payout (percent) | 200% |
Stock-based Compensation Plan_5
Stock-based Compensation Plans - Schedule of PSU and RSU Plans Activity (Details) - CAD ($) shares in Thousands, $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
PSUs | ||
Number of units (thousands) | ||
Outstanding, beginning of year (shares) | 1,898 | 1,976 |
Granted (shares) | 580 | 587 |
Notional dividends reinvested (shares) | 58 | 60 |
Paid out (shares) | (712) | (697) |
Cancelled/forfeited (shares) | (34) | (28) |
Outstanding, end of year (shares) | 1,790 | 1,898 |
Additional information ($ millions) | ||
Compensation expense recognized | $ 25 | $ 74 |
Compensation expense unrecognized | 24 | 33 |
Cash payout | 66 | 50 |
Accrued liability as at December 31 | 90 | 132 |
Aggregate intrinsic value as at December 31 | $ 114 | $ 165 |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Weighted-average contractual life (years) | 1 year | |
RSUs | ||
Number of units (thousands) | ||
Outstanding, beginning of year (shares) | 1,060 | 1,048 |
Granted (shares) | 331 | 378 |
Notional dividends reinvested (shares) | 29 | 32 |
Paid out (shares) | (410) | (371) |
Cancelled/forfeited (shares) | (33) | (27) |
Outstanding, end of year (shares) | 977 | 1,060 |
Additional information ($ millions) | ||
Compensation expense recognized | $ 16 | $ 26 |
Compensation expense unrecognized | 16 | 17 |
Cash payout | 25 | 21 |
Accrued liability as at December 31 | 40 | 46 |
Aggregate intrinsic value as at December 31 | $ 56 | $ 63 |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Weighted-average contractual life (years) | 1 year |
Stock-based Compensation Plan_6
Stock-based Compensation Plans - RSU Plans Narrative (Details) - RSUs | 12 Months Ended |
Dec. 31, 2022 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting period | 3 years |
Unit with underlying value equivalent to common shares | 1 |
Other Income, Net (Details)
Other Income, Net (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Other Income and Expenses [Abstract] | ||
Non-service component of net periodic benefit cost | $ 92 | $ 45 |
Equity component of AFUDC | 78 | 77 |
Interest income | 11 | 5 |
(Loss) gain on derivatives, net | (17) | 30 |
(Loss) gain on retirement investments, net | (18) | 4 |
Other | 19 | 12 |
Other income, net | $ 165 | $ 173 |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Income Tax Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Gross deferred income tax assets | ||
Regulatory liabilities | $ 674 | $ 560 |
Tax loss and credit carryforwards | 658 | 556 |
Employee future benefits | 161 | 169 |
Other | 160 | 91 |
Deferred tax assets, gross | 1,653 | 1,376 |
Valuation allowance | (32) | (23) |
Net deferred income tax asset | 1,621 | 1,353 |
Gross deferred income tax liabilities | ||
PPE | (5,146) | (4,571) |
Regulatory assets | (388) | (283) |
Intangible assets | (147) | (126) |
Deferred tax liabilities, gross | (5,681) | (4,980) |
Net deferred income tax liability | $ (4,060) | $ (3,627) |
Income Taxes - Schedule of Comp
Income Taxes - Schedule of Components of Income Tax Expense (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Canadian | ||
Earnings before income tax expense | $ 447 | $ 427 |
Current income tax | 93 | 84 |
Deferred income tax | (41) | (35) |
Total Canadian | 52 | 49 |
Foreign | ||
Earnings before income tax expense | 1,356 | 1,212 |
Current income tax | 14 | 3 |
Deferred income tax | 223 | 182 |
Total Foreign | 237 | 185 |
Income tax expense | $ 289 | $ 234 |
Income Taxes - Schedule of Effe
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | ||
Earnings before income tax expense | $ 1,803 | $ 1,639 |
Combined Canadian federal and provincial statutory income tax rate (%) | 30% | 30% |
Expected federal and provincial taxes at statutory rate | $ 541 | $ 492 |
Expected federal and provincial taxes at statutory rate decrease resulting from: | ||
Foreign and other statutory rate differentials | (162) | (155) |
AFUDC | (18) | (16) |
Effects of rate-regulated accounting: | ||
Difference between depreciation claimed for income tax and accounting purposes | (74) | (74) |
Items capitalized for accounting purposes but expensed for income tax purposes | (7) | (8) |
Other | 9 | (5) |
Income tax expense | $ 289 | $ 234 |
Effective tax rate (%) | 16% | 14.30% |
Income Taxes - Tax Carryforward
Income Taxes - Tax Carryforward (Details) $ in Millions | Dec. 31, 2022 CAD ($) |
Tax Credit Carryforward [Line Items] | |
Total income tax carryforwards recognized | $ 3,617 |
Canadian | |
Tax Credit Carryforward [Line Items] | |
Total income tax carryforwards recognized | |
Foreign | |
Tax Credit Carryforward [Line Items] | |
Federal and state net operating loss | 3,093 |
Tax carryforward, gross | 3,224 |
Non-capital loss | Canadian | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | 393 |
Other tax credits | Foreign | |
Tax Credit Carryforward [Line Items] | |
Tax credit carryforward | $ 131 |
Employee Future Benefits - Sche
Employee Future Benefits - Schedule of Allocation of and Fair Value of Plan Assets (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Defined Benefit Plan Disclosure [Line Items] | |||
2022 Target Allocation | 100% | ||
Actual Plan Asset Allocations (percent) | 100% | 100% | |
Fair value of plan assets | $ 3,468 | $ 4,162 | |
Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2022 Target Allocation | 47% | ||
Actual Plan Asset Allocations (percent) | 48% | 48% | |
Fair value of plan assets | $ 1,671 | $ 2,020 | |
Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2022 Target Allocation | 46% | ||
Actual Plan Asset Allocations (percent) | 43% | 45% | |
Fair value of plan assets | $ 1,488 | $ 1,861 | |
Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2022 Target Allocation | 6% | ||
Actual Plan Asset Allocations (percent) | 8% | 6% | |
Fair value of plan assets | $ 264 | $ 235 | |
Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 18 | $ 21 | |
Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2022 Target Allocation | 1% | ||
Actual Plan Asset Allocations (percent) | 1% | 1% | |
Fair value of plan assets | $ 27 | $ 25 | |
Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 870 | 978 | |
Level 1 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 666 | 749 | |
Level 1 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 199 | 219 | |
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 | 5 | 10 | |
Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 2,316 | 2,928 | |
Level 2 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,005 | 1,271 | |
Level 2 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,289 | 1,642 | |
Level 2 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
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 | 22 | 15 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 282 | 256 | $ 224 |
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 | 264 | 235 | |
Level 3 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 18 | 21 | |
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, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | $ 4,162 | |
Balance, end of year | 3,468 | $ 4,162 |
Level 3 | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | 256 | 224 |
Return on plan assets | 28 | 32 |
Foreign currency translation | 3 | 0 |
Purchases, sales and settlements | (5) | 0 |
Balance, end of year | $ 282 | $ 256 |
Employee Future Benefits - Sc_3
Employee Future Benefits - Schedule of Funded Status (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Change in value of plan assets | ||
Balance, beginning of year | $ 4,162 | |
Balance, end of year | 3,468 | $ 4,162 |
Other assets (Note 9) | 274 | 259 |
Other liabilities (Note 16) | (423) | (740) |
Defined Benefit Pension Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 3,922 | 3,995 |
Service costs | 106 | 109 |
Employee contributions | 18 | 18 |
Interest costs | 114 | 98 |
Benefits paid | (195) | (170) |
Actuarial gains | (1,026) | (111) |
Past service costs (credits)/plan amendments | 0 | (2) |
Foreign currency translation | 124 | (15) |
Balance, end of year | 3,063 | 3,922 |
Change in value of plan assets | ||
Balance, beginning of year | 3,722 | 3,528 |
Actual return on plan assets | (651) | 291 |
Benefits paid | (187) | (158) |
Employee contributions | 18 | 18 |
Employer contributions | 54 | 55 |
Foreign currency translation | 123 | (12) |
Balance, end of year | 3,079 | 3,722 |
Funded status | 16 | (200) |
Other assets (Note 9) | 188 | 204 |
Other current liabilities (Note 13) | (15) | (13) |
Other liabilities (Note 16) | (157) | (391) |
Net liabilities | 16 | (200) |
Accumulated benefit obligation | 2,818 | 3,586 |
OPEB Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 747 | 789 |
Service costs | 35 | 35 |
Employee contributions | 3 | 2 |
Interest costs | 21 | 19 |
Benefits paid | (29) | (25) |
Actuarial gains | (225) | (70) |
Past service costs (credits)/plan amendments | 1 | 0 |
Foreign currency translation | 29 | (3) |
Balance, end of year | 582 | 747 |
Change in value of plan assets | ||
Balance, beginning of year | 440 | 391 |
Actual return on plan assets | (77) | 48 |
Benefits paid | (24) | (21) |
Employee contributions | 3 | 2 |
Employer contributions | 19 | 22 |
Foreign currency translation | 28 | (2) |
Balance, end of year | 389 | 440 |
Funded status | (193) | (307) |
Other assets (Note 9) | 86 | 55 |
Other current liabilities (Note 13) | (13) | (13) |
Other liabilities (Note 16) | (266) | (349) |
Net liabilities | $ (193) | $ (307) |
Employee Future Benefits - Summ
Employee Future Benefits - Summary of Benefit Obligations and Fair Value Narrative (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected benefit obligation | $ 978 | $ 2,188 |
Plan with projected benefit obligation, fair value of plan assets | 790 | 1,799 |
Accumulated benefit obligation | 833 | 1,243 |
Plan with accumulated benefit obligation, fair value of plan assets | 790 | 1,063 |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | 310 | 398 |
Plan with accumulated benefit obligation, fair value of plan assets | $ 31 | $ 36 |
Employee Future Benefits - Sc_4
Employee Future Benefits - Schedule of Net Benefit Costs (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | $ 106 | $ 109 |
Interest costs | 114 | 98 |
Expected return on plan assets | (194) | (177) |
Amortization of actuarial losses (gains) | 4 | 36 |
Amortization of past service credits/plan amendments | (1) | (1) |
Regulatory adjustments | (10) | (1) |
Net Benefit Cost | 19 | 64 |
OPEB Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | 35 | 35 |
Interest costs | 21 | 19 |
Expected return on plan assets | (23) | (19) |
Amortization of actuarial losses (gains) | (10) | (2) |
Amortization of past service credits/plan amendments | (1) | (1) |
Regulatory adjustments | 4 | 3 |
Net Benefit Cost | $ 26 | $ 35 |
Employee Future Benefits - Comp
Employee Future Benefits - Components of AOCI and Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Regulatory assets (Note 8) | $ 4,009 | $ 3,589 |
Regulatory liabilities (Note 8) | (3,915) | (3,222) |
Defined Benefit Pension Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses (gains) | 9 | 33 |
Unamortized past service costs | 1 | 1 |
Income tax (recovery) expense | (2) | (8) |
Accumulated other comprehensive income | 8 | 26 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses (gains) | 103 | 260 |
Past service credits | (4) | (5) |
Other regulatory deferrals | (6) | 10 |
Net regulatory assets (liabilities) | 93 | 265 |
Regulatory assets (Note 8) | 207 | 376 |
Regulatory liabilities (Note 8) | (114) | (111) |
OPEB Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses (gains) | (11) | (5) |
Unamortized past service costs | 7 | 7 |
Income tax (recovery) expense | 1 | 0 |
Accumulated other comprehensive income | (3) | 2 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses (gains) | (195) | (81) |
Past service credits | (4) | (6) |
Other regulatory deferrals | 7 | 14 |
Net regulatory assets (liabilities) | (192) | (73) |
Regulatory assets (Note 8) | 0 | 12 |
Regulatory liabilities (Note 8) | $ (192) | $ (85) |
Employee Future Benefits - Co_2
Employee Future Benefits - Components Recognized in OCI and Regulatory Assets (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial gains | $ (23) | $ (10) |
Amortization of actuarial losses | 1 | 1 |
Foreign currency translation | (2) | 0 |
Income tax expense | 6 | 2 |
Total recognized in comprehensive income | (18) | (7) |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Current year net actuarial gains | (155) | (220) |
Past service cost/plan amendments | 0 | 0 |
Amortization of actuarial (losses) gains | (6) | (35) |
Amortization of past service credits | 1 | 2 |
Foreign currency translation | 4 | (2) |
Regulatory adjustments | (16) | (3) |
Total recognized in regulatory liabilities | (172) | (258) |
OPEB Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial gains | (6) | (4) |
Amortization of actuarial losses | 0 | 0 |
Foreign currency translation | 0 | 0 |
Income tax expense | 1 | 1 |
Total recognized in comprehensive income | (5) | (3) |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Current year net actuarial gains | (118) | (95) |
Past service cost/plan amendments | 1 | 0 |
Amortization of actuarial (losses) gains | 10 | 2 |
Amortization of past service credits | 1 | 2 |
Foreign currency translation | (6) | 0 |
Regulatory adjustments | (7) | (4) |
Total recognized in regulatory liabilities | $ (119) | $ (95) |
Employee Future Benefits - Sc_5
Employee Future Benefits - Schedule of Assumptions Used (Details) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 2.97% | 2.60% |
Discount rate as at December 31 | 5.27% | 3% |
Expected long-term rate of return on plan assets | 5.87% | 5.40% |
Rate of compensation increase | 3.33% | 3.30% |
Health care cost trend increase as at December 31 | 0% | 0% |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 2.97% | 2.60% |
Discount rate as at December 31 | 5.36% | 2.97% |
Expected long-term rate of return on plan assets | 5% | 4.88% |
Rate of compensation increase | 0% | 0% |
Health care cost trend increase as at December 31 | 4.48% | 4.49% |
Health care cost trend rate assumed for next fiscal year | 6.17% | |
Remaining period until health care cost trend rate reaches ultimate trend rate | 12 years |
Employee Future Benefits - Sc_6
Employee Future Benefits - Schedule of Expected Benefit Payments (Details) $ in Millions | Dec. 31, 2022 CAD ($) |
Defined Benefit Pension Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2023 | $ 177 |
2024 | 183 |
2025 | 190 |
2026 | 197 |
2027 | 203 |
2028-2032 | 1,094 |
OPEB Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2023 | 30 |
2024 | 32 |
2025 | 33 |
2026 | 35 |
2027 | 35 |
2028-2032 | $ 191 |
Employee Future Benefits - Defi
Employee Future Benefits - Defined Contribution Plan Narrative (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Defined contribution plan cost recognized | $ 47 | $ 44 |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Expected contributions for next fiscal year | 35 | |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Expected contributions for next fiscal year | $ 20 |
Supplementary Cash Flow Infor_3
Supplementary Cash Flow Information (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Cash paid (received) for | ||
Interest | $ 1,057 | $ 986 |
Income taxes | 79 | (13) |
Change in working capital | ||
Accounts receivable and other current assets | (479) | (88) |
Prepaid expenses | (22) | (15) |
Inventories | (153) | (56) |
Regulatory assets - current portion | (307) | (99) |
Accounts payable and other current liabilities | 449 | 164 |
Regulatory liabilities - current portion | 33 | (50) |
Change in working capital | (479) | (144) |
Non-cash investing and financing activities | ||
Accrued capital expenditures | 411 | 432 |
Common share dividends reinvested | 364 | 356 |
Contributions in aid of construction | $ 13 | $ 13 |
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 | ||||
Sep. 30, 2022 CAD ($) | Sep. 30, 2022 USD ($) | May 31, 2022 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | May 31, 2022 USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Unrealized losses recognized in regulatory assets | $ 4,009 | $ 3,589 | ||||
Unrealized gains recognized as regulatory liabilities | 3,915 | 3,222 | ||||
Mutual funds and money market accounts | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Unrealized gain (loss) on investments | $ (11) | 5 | ||||
UNS Energy | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Realized gains shared with customers, percent | 10% | |||||
ITC | Unsecured Senior Notes, September Issuance, 2027 Maturity | Unsecured | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Face value | $ 600 | |||||
Stated interest rate (percent) | 4.95% | |||||
Fortis | Unsecured Senior Notes, May Issuance, 2029 Maturity | Unsecured | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Face value | $ 500 | |||||
Stated interest rate (percent) | 4.43% | 4.43% | ||||
Energy contracts subject to regulatory deferral | Derivative instrument | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Unrealized gains recognized as regulatory liabilities | $ 224 | 52 | ||||
Energy contracts subject to regulatory deferral | Derivative instrument | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Unrealized losses recognized in regulatory assets | 84 | 20 | ||||
Energy contracts not subject to regulatory deferral | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Unrealized gains recognized in revenue | 34 | 21 | ||||
Total return swaps | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Notional amount of derivative | 114 | |||||
Unrealized gains (losses) on total return swaps recognized in other income, net | $ (22) | 17 | ||||
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 | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Notional amount of derivative | $ 352 | |||||
Unrealized gains (losses) on total return swaps recognized in other income, net | (9) | $ (11) | ||||
Interest rate swaps | ITC | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Notional amount of derivative | $ 450 | |||||
Derivative terms | 5 years | 5 years | ||||
Realized gain recognized in other comprehensive income | $ 52 | $ 39 | ||||
Cross Currency Interest Rate Contract | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Notional amount of derivative | $ 391 | |||||
Cross Currency Interest Rate Contract | Fortis | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Notional amount of derivative | $ 391 | |||||
Derivative terms | 7 years | |||||
Unrealized gains (losses) on total return swaps recognized in other income, net | $ (17) | |||||
Interest rate | 4.34% | 4.34% |
Fair Value of Financial Instr_4
Fair Value of Financial Instruments and Risk Management - Fair Value Hierarchy (Details) - Recurring - CAD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Assets | ||
Other investments | $ 150 | $ 137 |
Assets, total fair value | 503 | 256 |
Liabilities | ||
Liabilities, total fair value | (198) | (49) |
Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 304 | 78 |
Liabilities | ||
Liabilities | (164) | (46) |
Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 49 | 16 |
Liabilities | ||
Liabilities | (8) | (3) |
Foreign exchange contracts, total return and interest rate swaps | ||
Assets | ||
Assets | 25 | |
Liabilities | ||
Liabilities | (26) | |
Level 1 | ||
Assets | ||
Other investments | 150 | 137 |
Assets, total fair value | 150 | 160 |
Liabilities | ||
Liabilities, total fair value | 0 | 0 |
Level 1 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | 0 |
Level 1 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | 0 |
Level 1 | Foreign exchange contracts, total return and interest rate swaps | ||
Assets | ||
Assets | 23 | |
Liabilities | ||
Liabilities | 0 | |
Level 2 | ||
Assets | ||
Other investments | 0 | 0 |
Assets, total fair value | 353 | 96 |
Liabilities | ||
Liabilities, total fair value | (198) | (49) |
Level 2 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 304 | 78 |
Liabilities | ||
Liabilities | (164) | (46) |
Level 2 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 49 | 16 |
Liabilities | ||
Liabilities | (8) | (3) |
Level 2 | Foreign exchange contracts, total return and interest rate swaps | ||
Assets | ||
Assets | 2 | |
Liabilities | ||
Liabilities | (26) | |
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, total return and interest rate swaps | ||
Assets | ||
Assets | $ 0 | |
Liabilities | ||
Liabilities | $ 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, 2022 | Dec. 31, 2021 |
Derivative assets | ||
Gross Amount Recognized In Balance Sheet | $ 353 | $ 94 |
Counterparty Netting of Energy Contracts | 54 | 25 |
Cash Collateral Received/Posted | 63 | 7 |
Net Amount | 236 | 62 |
Derivative liabilities | ||
Gross Amount Recognized In Balance Sheet | (172) | (49) |
Counterparty Netting of Energy Contracts | (54) | (25) |
Cash Collateral Received/Posted | 0 | 0 |
Net Amount | $ (118) | $ (24) |
Fair Value of Financial Instr_6
Fair Value of Financial Instruments and Risk Management - Volume of Derivative Activity (Details) | 12 Months Ended | |
Dec. 31, 2022 GWh petajoule | Dec. 31, 2021 GWh petajoule | |
Electricity swap contracts, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 586 | 509 |
Electricity power purchase contracts, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 224 | 731 |
Gas swap contracts, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | petajoule | 185 | 151 |
Gas supply contract premiums, Energy contracts subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | petajoule | 148 | 144 |
Wholesale trading contracts, Energy contracts not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 1,886 | 1,886 |
Gas swap contracts, Energy contracts not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | petajoule | 34 | 29 |
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, 2022 | Dec. 31, 2021 | |
Fair Value, Concentration Risk, Financial Statement Captions [Line Items] | ||
Uncollectible write-off deferral, exceed customer rate collected threshold | 0.0010 | |
Value of derivative instruments in net liability positions | $ 178 | $ 59 |
Revenue | Three customers | Customer Concentration Risk | ITC | ||
Fair Value, Concentration Risk, Financial Statement Captions [Line Items] | ||
Concentration risk percentage | 70% |
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, 2022 | Dec. 31, 2021 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Unhedged foreign net investments | $ 10.6 | $ 10.8 |
Designated as hedging instrument | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Long-term debt designated as an effective hedge | $ 2.9 | $ 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, 2022 | Dec. 31, 2021 |
Carrying Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion | $ 28.6 | $ 25.5 |
Estimated Fair Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion | $ 25.8 | $ 28.8 |
Commitments and Contingencies -
Commitments and Contingencies - Fiscal Year Maturity (Details) $ in Millions | 1 Months Ended | 12 Months Ended |
Apr. 30, 2015 | Dec. 31, 2022 CAD ($) GWh agreement_renewal MW | |
Purchase obligations: | ||
Total | $ 12,504 | |
Year 1 | 1,599 | |
Year 2 | 995 | |
Year 3 | 883 | |
Year 4 | 782 | |
Year 5 | 656 | |
Thereafter | 7,589 | |
Gas and fuel purchase obligations | ||
Purchase obligations: | ||
Total | 5,720 | |
Year 1 | 1,024 | |
Year 2 | 516 | |
Year 3 | 461 | |
Year 4 | 374 | |
Year 5 | 328 | |
Thereafter | 3,017 | |
Gas and fuel purchase obligations | FortisBC Energy | ||
Purchase obligations: | ||
Total | 4,804 | |
Gas and fuel purchase obligations | UNS Energy | ||
Purchase obligations: | ||
Total | 801 | |
Renewable gas, expiring 2044 | FortisBC Energy | ||
Purchase obligations: | ||
Total | 2,720 | |
Gas, renewable gas, gas transportation and storage servives, expiring in 2062 | FortisBC Energy | ||
Purchase obligations: | ||
Total | 2,084 | |
Waneta Expansion capacity agreement | ||
Purchase obligations: | ||
Total | 2,472 | |
Year 1 | 54 | |
Year 2 | 55 | |
Year 3 | 56 | |
Year 4 | 58 | |
Year 5 | 59 | |
Thereafter | 2,190 | |
Waneta Expansion capacity agreement | FortisBC Electric | ||
Purchase obligations: | ||
Purchase commitment term | 40 years | |
Renewable PPAs | ||
Purchase obligations: | ||
Total | 1,926 | |
Year 1 | 131 | |
Year 2 | 131 | |
Year 3 | 131 | |
Year 4 | 131 | |
Year 5 | 130 | |
Thereafter | $ 1,272 | |
Renewable PPAs | TEP and UNS Electric | ||
Purchase obligations: | ||
Share of plant output, percentage | 100% | |
Power purchase obligations | ||
Purchase obligations: | ||
Total | $ 1,691 | |
Year 1 | 334 | |
Year 2 | 253 | |
Year 3 | 191 | |
Year 4 | 192 | |
Year 5 | 113 | |
Thereafter | 608 | |
Power purchase obligations | FortisBC Electric | ||
Purchase obligations: | ||
Total | $ 258 | |
Purchase commitment term | 20 years | |
Power purchase obligations | FortisBC Electric | Maximum | ||
Purchase obligations: | ||
Amount of volume required (in mw) | MW | 200 | |
Volume of energy required to be purchased (in GWh) | GWh | 1,752 | |
Power purchase obligations | UNS Energy | ||
Purchase obligations: | ||
Total | $ 153 | |
Power purchase obligations | UNS Energy | Maximum | ||
Purchase obligations: | ||
Amount of volume required (in mw) | MW | 300 | |
Power purchase obligations | Maritime Electric | ||
Purchase obligations: | ||
Total | $ 746 | |
Amount of volume required (in mw) | MW | 30 | |
Power purchase obligations | Maritime Electric | Nuclear Generating Station | ||
Purchase obligations: | ||
Share of plant output, percentage | 4.55% | |
Power purchase obligations | FortisOntario | ||
Purchase obligations: | ||
Total | $ 489 | |
Power purchase obligations | FortisOntario | Maximum | ||
Purchase obligations: | ||
Amount of volume required (in mw) | MW | 145 | |
Power purchase obligations | FortisOntario | Minimum | ||
Purchase obligations: | ||
Volume of energy required to be purchased (in GWh) | GWh | 537 | |
ITC easement agreement | ||
Purchase obligations: | ||
Total | $ 380 | |
Year 1 | 14 | |
Year 2 | 14 | |
Year 3 | 14 | |
Year 4 | 14 | |
Year 5 | 14 | |
Thereafter | $ 310 | |
ITC easement agreement | ITC | ||
Purchase obligations: | ||
Number of agreement renewals | agreement_renewal | 10 | |
Agreement renewal term | 50 years | |
Notice, period in advance | 1 year | |
Debt collection agreement | ||
Purchase obligations: | ||
Total | $ 106 | |
Year 1 | 3 | |
Year 2 | 3 | |
Year 3 | 3 | |
Year 4 | 3 | |
Year 5 | 3 | |
Thereafter | 91 | |
Renewable energy credit purchase agreement | ||
Purchase obligations: | ||
Total | 77 | |
Year 1 | 18 | |
Year 2 | 14 | |
Year 3 | 7 | |
Year 4 | 7 | |
Year 5 | 6 | |
Thereafter | 25 | |
Other | ||
Purchase obligations: | ||
Total | 132 | |
Year 1 | 21 | |
Year 2 | 9 | |
Year 3 | 20 | |
Year 4 | 3 | |
Year 5 | 3 | |
Thereafter | $ 76 |
Commitments and Contingencies_2
Commitments and Contingencies - Other Commitments Narrative (Details) | 12 Months Ended |
Dec. 31, 2022 CAD ($) | |
Wataynikaneyap Partnership | |
Other Commitments [Line Items] | |
Equity investment ownership (percent) | 39% |
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 | 339,000,000 |
Obligation under guarantee | 0 |
CH Energy Group | Payment Guarantee | |
Other Commitments [Line Items] | |
Maximum commitment | 74,000,000 |
Obligation under guarantee | 0 |
FHI | Indirect Guarantee of Indebtedness | |
Other Commitments [Line Items] | |
Maximum commitment | $ 142,000,000 |
Commitments and Contingencies_3
Commitments and Contingencies - Contingency Narrative (Details) | Dec. 31, 2022 CAD ($) |
Claim related to pipeline rights | FHI and Fortis | |
Site Contingency [Line Items] | |
Contingency accrual | $ 0 |